Petition of TPL-008-1

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

North American Electric Reliability Corporation

)
)

Docket No. ______

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD TPL-008-1
Lauren A. Perotti
Assistant General Counsel
North American Electric Reliability
Corporation
1401 H Street NW, Suite 410
Washington, D.C. 20005
202-400-3000
[email protected]
Counsel for the North American Electric
Reliability Corporation

December 17, 2024

TABLE OF CONTENTS
I.

SUMMARY ............................................................................................................................ 2

II.

NOTICES AND COMMUNICATIONS ................................................................................ 5

III. REGULATORY BACKGROUND ........................................................................................ 5
A.

Regulatory Framework ....................................................................................................... 5

B.

NERC Reliability Standards Development Procedure ....................................................... 6

IV. THE NEED FOR ENHANCED TRANSMISSION PLANNING STANDARDS FOR
EXTREME WEATHER CONDITIONS ........................................................................................ 7
A.

Overview of NERC Transmission Planning Reliability Standards .................................... 8

B. Order No. 896 Directs the Development of Reliability Standards Addressing
Transmission Planning for Extreme Heat and Extreme Cold Events ......................................... 9
V. JUSTIFICATION FOR APPROVAL: PROPOSED RELIABILITY STANDARD TPL008-1 ............................................................................................................................................. 14
A.

Proposed Glossary Term: Extreme Temperature Assessment.......................................... 16

B.

Title, Purpose, and Applicability ...................................................................................... 16

C. A New Framework for Wide-Area Coordination in the Performance of Extreme
Temperature Assessments ......................................................................................................... 16
D.

Requirement R1 ................................................................................................................ 19

E.

Requirement R2 ................................................................................................................ 20
1.

Benchmark Temperature Event Criteria ....................................................................... 21

2.

Attachment 1: Extreme Temperature Assessment Zones ............................................. 26

F.

Requirement R3 ................................................................................................................ 28
1.

Consideration of Directive: Order No. 896 paragraph 39............................................. 31

2.

Consideration of Directive: Order No. 896 paragraph 72............................................. 31

3.

Consideration of Directive: Order No. 896 paragraph 76............................................. 32

4.

Consideration of Directives: Order No. 896 paragraphs 88 and 92 .............................. 32

5.

Consideration of Directives: Order No. 896 paragraphs 124 and 125 .......................... 33

G.

H.

Requirement R4 ................................................................................................................ 34
6.

Consideration of Directive: Order No. 896 paragraph 39............................................. 36

7.

Consideration of Directive: Order No. 896 paragraph 72............................................. 36

8.

Consideration of Directives: Order No. 896 paragraphs 88 and 92 .............................. 36

9.

Consideration of Directives: Order No. 896 paragraphs 116-117 ................................ 37
Requirement R5 ................................................................................................................ 38
i

TABLE OF CONTENTS
I.

Requirement R6 ................................................................................................................ 38

J.

Requirement R7 ................................................................................................................ 39

K.

Requirement R8 ................................................................................................................ 44

L.

Requirement R9 ................................................................................................................ 45

M.

Requirement R10 .......................................................................................................... 49

N.

Requirement R11 .............................................................................................................. 51

O. Consideration of Order No. 896 Directives Regarding Probabilistic Analysis and the
MOD-032 Standard................................................................................................................... 52
1. Paragraphs 134, 138 Directives for Consideration of Including Probabilistic Elements
in Extreme Temperature Planning Studies ........................................................................... 52
2.

Paragraph 73, Regarding Modifications to the MOD-032 Standard ............................ 57

VI. ENFORCEABILITY OF PROPOSED RELIABILITY STANDARDS .............................. 58
VII. EFFECTIVE DATE OF THE PROPOSED RELIABILITY STANDARDS....................... 58
VIII.CONCLUSION ..................................................................................................................... 60

ii

TABLE OF CONTENTS
EXHIBITS
Exhibit A
Exhibit B
Exhibit C
Exhibit D
Exhibit E
Exhibit F
Exhibit G
Exhibit H

Proposed Reliability Standard TPL-008-1
Implementation Plan
Order No. 672 Criteria
Consideration of Order No. 896 Directives
Technical Rationale
Analysis of Violation Risk Factors and Violation Severity Levels
Summary of Development History and Complete Record of Development
Standard Drafting Team Roster

iii

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability Corporation

)
)

Docket No. _______

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD TPL-008-1
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”) 1 and Section 39.5 of the
regulations of the Federal Energy Regulatory Commission (“FERC” or “Commission”), 2 the
North American Electric Reliability Corporation (“NERC”) 3 hereby submits for Commission
approval proposed Reliability Standard TPL-008-1 – Transmission System Planning Performance
Requirements for Extreme Temperature Events. The proposed Reliability Standard 4 would
advance the reliability of the Bulk-Power System by improving how the entities responsible for
planning for the reliable operation of the North American interconnected transmission systems
plan for the wide-area impacts of extreme heat and cold temperature events, particularly when
their systems are facing unexpectedly high demand. These enhanced planning requirements are
timely and necessary. Extreme temperature events have increased in frequency in recent years and
are projected to increase further in the future, 5 and experience demonstrates these events can result
in widespread and severe impacts on the reliability of the Bulk-Power System.

16 U.S.C. § 824o.
18 C.F.R. § 39.5 (2024).
3
The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with Section
215 of the FPA. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006) [hereinafter ERO Certification Order].
4
Unless otherwise indicated, terms capitalized in this filing shall have the meaning provided in the Glossary
of Terms used in NERC Reliability Standards,
https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
5
See, e.g., U.S. Environmental Protection Agency, Climate Change Indicators: Weather and Climate (2024)
(EPA Climate Change Indicators), https://www.epa.gov/climate-indicators/weather-climate.
1
2

1

As explained more fully herein, proposed Reliability Standard TPL-008-1 is responsive to
the Commission’s directives in Order No. 896, in which the Commission directed NERC to submit
new or revised standards that would address concerns pertaining to transmission system planning
for extreme heat and cold weather events by December 23, 2024. 6
NERC requests that the Commission approve the proposed Reliability Standard, provided
in Exhibit A hereto, as just, reasonable, not unduly discriminatory or preferential, and in the public
interest. NERC also requests approval of: (1) the associated Implementation Plan (Exhibit B); and
the associated Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) for the
proposed Reliability Standard (Exhibit F).
As required by Section 39.5(a) of the Commission’s regulations, 7 this petition presents the
technical basis and purpose of the proposed Reliability Standard, a summary of the development
history, including the adoption of the proposed Reliability Standards by the NERC Board of
Trustees on December 10, 2024 (Exhibit G), and a demonstration that the proposed Reliability
Standard meets the criteria identified by the Commission in Order No. 672 8 (Exhibit C).
I.

SUMMARY
Over the last several years, NERC has made the development of Reliability Standards

addressing extreme weather conditions a high priority. Multiple events since 2011 have
demonstrated the impacts extreme heat and extreme cold conditions can have on the reliability of
the Bulk-Power System, underscoring the need to address the root causes and lessons learned as
expeditiously as possible. From 2021 through the present, NERC has developed a series of

Order No. 896, Transmission System Planning Performance Requirements for Extreme Weather, 183 FERC
¶ 61,191 (2023) [hereinafter Order No. 896].
7
18 C.F.R. § 39.5(a).
8
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
262, 321-37 (2006) [hereinafter Order No. 672], order on reh’g, Order No. 672-A, 114 FERC 61,328 (2006).
6

2

Reliability Standards to address preparedness and operations during extreme cold weather
conditions, as recommended in the reports of the joint inquiry teams examining grid operations
during the 2018 and 2021 winter storm events affecting Texas and the South Central United
States. 9 NERC has also initiated standard development projects to address energy assurance issues
raised by extreme weather events concurrent with the growing reliance on generating units
supported by natural gas infrastructure that may not be able to deliver fuel when impacted by
extreme cold temperatures, and on weather-dependent (wind and solar) variable energy
resources. 10
Proposed Reliability Standard TPL-008-1 would build upon these efforts and advance the
reliability of the Bulk-Power System by improving how entities plan for extreme heat and extreme
cold weather events as part of long-term transmission system planning. By modeling and studying
the potential impacts of widespread extreme heat and cold events on the reliable operation of the

To address the findings of these reports, NERC developed Reliability Standards EOP-011-2, IRO-010-4,
and TOP-003-5 in 2021, Reliability Standards EOP-011-3 and EOP-012-1 in 2022; Reliability Standards TOP-002-5
and EOP-011-4 in 2023; and Reliability Standard EOP-012-2 in early 2024. As directed by the Commission, an
additional project is underway to provide further clarification of the requirements of Reliability Standard EOP-012-2
addressing generator cold weather preparedness by March 2025.
For more information on the recommendations addressed in these projects, see 2019 FERC and NERC
Staff Report: The South Central United States Cold Weather Bulk Electric System Event of January 17, 2018 (Jul.
2019), https://www.nerc.com/pa/rrm/ea/Documents/South_Central_Cold_Weather_Event_FERC-NERCReport_20190718.pdf, and FERC, NERC, and Regional Entity Staff, The February 2021 Cold Weather Outages in
Texas and the South Central United States (Nov. 2021), https://www.ferc.gov/media/february-2021-cold-weatheroutages-texas-and-south-central-united-states-ferc-nerc-and. A third report, issued following a December 2022 event
affecting the eastern United States, stressed the need for improvements to Cold Weather Reliability Standards
consistent with the February 2021 Event Report findings, and recommended improvements for natural gas
infrastructure in the United States. See FERC, NERC, and Regional Entity Staff, Inquiry into Bulk-Power System
Operations During December 2022 Winter Storm Elliot (Oct. 2023), https://www.ferc.gov/media/winter-stormelliott-report-inquiry-bulk-power-system-operations-during-december-2022.
10
For more information on these projects, see Project 2022-03 Energy Assurance with Energy Constrained
Resources, https://www.nerc.com/pa/Stand/Pages/Project2022-03EnergyAssurancewithEnergyConstrainedResources.aspx (developing proposed Reliability Standards TOP-003-7 and BAL-007-1 addressing
energy assurance issues in the operations horizon) and Project 2024-02 Planning Energy Assurance,
https://www.nerc.com/pa/Stand/Pages/Project-2024-02-Planning-Energy-Assurance.aspx (addressing energy
assurance issues in the planning horizon).
9

3

Bulk-Power System in advance, entities can develop Corrective Action Plans or evaluate other
mitigating actions to avoid the worst of these impacts.
The proposed Reliability Standard consists of a framework, consisting of 11 requirements,
for the performance of periodic studies assessing the wide-area impacts of extreme heat and
extreme cold temperature events on the Bulk-Power System. These periodic studies are referred
to as Extreme Temperature Assessments. Proposed Reliability Standard TPL-008-1 would require
planning entities in a planning zone, defined in Attachment 1 of the standard, to coordinate with
each other on the development of Extreme Temperature Assessments. The proposed standard
contains requirements addressing wide-area coordination among planning entities, the
identification of benchmark temperature events and the development of planning cases based on
the benchmark temperature events, requirements for steady state and transient stability analyses
including sensitivity cases, requirements for entities to develop Corrective Action Plans in
specified instances where system performance requirements are not met, and requirements for the
sharing of study information and any Corrective Action Plans developed to address system
performance issues. Proposed Reliability Standard TPL-008-1 would require planning entities to
complete an Extreme Temperature Assessment at least once every five years, with the first
Extreme Temperature Assessment to be completed approximately five years following regulatory
approval of the proposed standard.
As discussed more fully in this petition, the proposed Reliability Standard fully addresses
the Commission’s directives in Order No. 896 to develop a Reliability Standard that would
improve transmission planning for extreme heat and cold temperature conditions.

4

For these reasons, which are summarized here and stated more fully below, NERC requests
that the Commission approve proposed Reliability Standard TPL-008-1, provided in Exhibit A
hereto, as just, reasonable, not unduly discriminatory or preferential, and in the public interest.

II.

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

following: 11
Lauren A. Perotti
Assistant General Counsel
North American Electric Reliability
Corporation
1401 H Street NW
Suite 410
Washington, D.C. 20005
202-400-3000
[email protected]

III.

REGULATORY BACKGROUND
A.

Soo Jin Kim
Vice President, Engineering and Standards
Jamie Calderon
Director, Standards Development
North American Electric Reliability
Corporation
1401 H Street NW
Suite 410
Washington, D.C. 20005
202-400-3000
[email protected]
[email protected]

Regulatory Framework

By enacting the Energy Policy Act of 2005, 12 Congress entrusted the Commission with the
duties of approving and enforcing rules to ensure the reliability of the Bulk-Power System, and
with the duty of certifying an ERO that would be charged with developing and enforcing
mandatory Reliability Standards, subject to Commission approval. Section 215(b)(1) of the FPA
states that all users, owners, and operators of the Bulk-Power System in the United States will be
subject to Commission-approved Reliability Standards. 13 Section 215(d)(5) of the FPA authorizes

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.
12
16 U.S.C. § 824o.
13
Id. § 824(b)(1).
11

5

the Commission to order the ERO to submit a new or modified Reliability Standard. 14 Section
39.5(a) of the Commission’s regulations requires the ERO to file for Commission approval each
Reliability Standard that the ERO proposes should become mandatory and enforceable in the
United States, and each modification to a Reliability Standard that the ERO proposes to make
effective. 15
The Commission has the regulatory responsibility to approve Reliability Standards that
protect the reliability of the Bulk-Power System and to ensure that such Reliability Standards are
just, reasonable, not unduly discriminatory or preferential, and in the public interest. Pursuant to
Section 215(d)(2) of the FPA and Section 39.5(c) 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. 16
B.

NERC Reliability Standards Development Procedure

The proposed Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process. 17 NERC
develops Reliability Standards in accordance with Section 300 (Reliability Standards
Development) of its Rules of Procedure and the NERC Standard Processes Manual. 18 In its ERO
Certification Order, the Commission found that NERC’s proposed rules provide for reasonable
notice and opportunity for public comment, due process, openness, and a balance of interests in
developing Reliability Standards and thus satisfies certain criteria for approving Reliability

Id. § 824o(d)(5).
18 C.F.R. § 39.5(a).
16
16 U.S.C. § 824o(d)(2); 18 C.F.R. § 39.5(c)(1).
17
Order No. 672 at P 334.
18
The NERC Rules of Procedure are available at https://www.nerc.com/AboutNERC/Pages/Rules-ofProcedure.aspx. The NERC Standard Processes Manual is available at
https://www.nerc.com/AboutNERC/RulesOfProcedure/Appendix_3A_SPM_Clean_Mar2019.pdf.
14
15

6

Standards. 19 The development process is open to any person or entity with a legitimate interest in
the reliability of the Bulk-Power System. NERC considers the comments of all stakeholders.
Further, a vote of stakeholders and adoption by the NERC Board of Trustees is required before
NERC submits the Reliability Standard to the Commission for approval.
IV.

THE NEED FOR ENHANCED TRANSMISSION PLANNING STANDARDS FOR
EXTREME WEATHER CONDITIONS
Multiple events since 2011 have demonstrated the impacts extreme heat and extreme cold

conditions can have on the reliability of the Bulk-Power System. Proposed Reliability Standard
TPL-008-1 would improve how entities plan for extreme heat and extreme cold weather events as
part of long-term transmission system planning. By modeling and studying the potential impacts
of wide-area extreme heat and extreme cold events on the reliability of the Bulk-Power System in
advance, entities would be able to take actions to avoid the worst of these impacts. The proposed
Reliability Standard, developed in response to the Commission’s directives in Order No. 896,
would address a gap in the currently effective Transmission Planning (TPL) Reliability Standards
relating to extreme temperature conditions.
This section provides background information regarding the need for a Reliability Standard
addressing transmission planning for extreme temperature conditions. This section includes a
discussion of the current NERC Transmission Planning (TPL) Reliability Standards framework,
as well as a discussion of the considerations underlying Order No. 896, in which the Commission
directed the development of new or revised Reliability Standards addressing transmission system
planning for extreme heat and extreme cold conditions. This section also provides a summary of
the Commission’s directives from Order No. 896, each of which is addressed in proposed
Reliability Standard TPL-008-1.
19

ERO Certification Order at P 250.

7

A.

Overview of NERC Transmission Planning Reliability Standards

The Transmission Planning (TPL) Reliability Standards set forth requirements for Planning
Authorities and Transmission Planners to develop studies of their portions of the Bulk-Power
System. These Reliability Standards help improve the reliability of the Bulk-Power System by
requiring planning entities to study how their system would perform under certain conditions,
system events, and scenarios, and to take actions when studies indicate the system would not
perform as required. There are currently two Transmission Planning (TPL) Reliability Standards
in effect: Reliability Standard TPL-001-5.1 – Transmission System Planning Performance
Requirements, and Reliability Standard TPL-007-4 – Transmission System Planned Performance
for Geomagnetic Disturbance Events.
Reliability Standard TPL-001-5.1 – Transmission System Planning Performance
Requirements requires each Planning Coordinator and Transmission Planner to perform an annual
Planning Assessment 20 of its portion of the Bulk Electric System covering the System conditions
and Contingencies described in the standard. Reliability Standard TPL-001-5.1 employs a riskbased approach to the study of Contingencies and the types of corrective action that are required
if the planning entity’s system cannot meet the performance requirements of the standard. For the
scenarios considered to set the stage for the design basis of the desired system performance and
are critical to ensure the reliable operation of the Bulk Power System (“planning events”), the
planning entity must develop a Corrective Action Plan if it determines, through its studies, that its
system would not meet the design basis laid out in the Reliability Standard. For the scenarios
considered to be less likely but could result in potentially severe impacts (“extreme events”), the
planning entity must conduct a comprehensive analysis to understand both the potential impacts
“Planning Assessment” is defined in the NERC Glossary as a “documented evaluation of future Transmission
System performance and Corrective Action Plans to remedy identified deficiencies.

20

8

on its system and the types of actions that could reduce or mitigate those impacts. The standard
requires Transmission Planners and Planning Coordinators to evaluate, as part of extreme event
steady state analysis, wide-area events affecting the transmission system. These events may
include loss of two generating stations resulting from conditions such as wildfires, extreme
weather, or other events based on operating experience, that may result in wide-area disturbances.
Entities, however, are not required to develop Corrective Action Plans to address any system
performance issues identified through these extreme event studies. 21
Reliability Standard TPL-007-4 – Transmission System Planned Performance for
Geomagnetic Disturbance Events addresses transmission system planning for geomagnetic
disturbance (“GMD”) events. This standard requires each responsible Planning Authority and
Transmission Planner to conduct a GMD Vulnerability Assessment at least once every sixty
calendar months assessing the impact of both a “benchmark” 1-in-100 year GMD event and a
“supplemental” GMD event reflecting a localized geoelectric field enhancement on its system.
Where the results of the studies indicate that the system would not meet performance requirements
(i.e. the system would experience voltage collapse, Cascading, or uncontrolled islanding), the
planning entity must develop a Corrective Action Plan to address how the performance
requirements would be met.
B.

Order No. 896 Directs the Development of Reliability Standards Addressing
Transmission Planning for Extreme Heat and Extreme Cold Events

On June 15, 2023, the Commission issued Order No. 896, a final rule directing NERC to
develop a new Reliability Standard or modifications to Reliability Standard TPL-001-5.1 that
would address concerns pertaining to transmission system planning for extreme heat and cold

21

See Reliability Standard TPL-001-5.1 Table 1 – Steady State & Stability Performance Extreme Events.

9

weather events. 22 The Commission directed NERC to submit a responsive standard within 18
months of publication of the final rule in the Federal Register, or by December 23, 2024. 23
In the order, the Commission noted that the country has experienced multiple major
extreme heat and cold weather events since 2011; each of these events put stress on the BulkPower System and resulted in load shed, and some of these events nearly resulted in system
collapse and uncontrolled blackouts which were avoided due to system operator actions. 24 The
Commission further noted that the frequency and magnitude of wide-area extreme heat and cold
weather events are expected to increase in future years. 25 The Commission continued: “Given the
reliability risks associated with extreme heat and cold weather events, including the potential for
widespread blackouts, maintaining the reliability of the Bulk-Power System requires transmission
system planning to account for the potential impact of extreme heat and cold weather over wide
geographical areas, and to consider the changing resource mix.” 26
While finding that the TPL-001 Reliability Standard includes provisions for Transmission
Planners and Planning Coordinators to study system performance under extreme events based on
their experience, the Commission found that the standard does not specifically require entities to
conduct performance analysis for extreme heat and cold weather. The Commission thus found that
there was a reliability gap in system planning. 27 To address this reliability gap, the Commission
directed NERC to develop a new or revised Reliability Standard addressing transmission system
planning for extreme heat and cold events, and to include the following in its proposed standard:

Order No. 896, Transmission System Planning Performance Requirements for Extreme Weather, 183 FERC
¶ 61,191 (2023).
23
Id. at P 188.
24
Order No 896 at PP 4, 20.
25
Id. at P 21.
26
Id. at P 5; see also id. at P 22.
27
Order No. 896 at PP 5, 23.
22

10

1. The development of benchmark planning cases based on major prior extreme heat and
cold weather events and/or meteorological projections;
2. Planning for extreme heat and cold weather events using steady state and transient
stability analyses expanded to cover a range of extreme weather scenarios including
the expected resource mix's availability during extreme heat and cold weather
conditions, and including the wide-area impacts of extreme heat and cold weather; and
3. Development of corrective action plans that mitigate specified instances where
performance requirements for extreme heat and cold weather events are not met. 28
With respect to the first item above, the Commission directed NERC to: (1) develop
extreme heat and cold weather benchmark events; and (2) require the development of benchmark
planning cases based on identified benchmark events. 29 With respect to benchmark events, the
Commission stated that NERC should consider approaches such as the use of projected frequency
or probability distribution, or other approaches achieving the objectives of the final rule, in
developing benchmark events. 30 The Commission further stated that all entities likely to be
impacted by the same extreme weather events should use consistent benchmark events, so that
they may coordinate their assumptions accordingly, 31 and that the benchmark events should
“reflect regional differences in climate and weather patterns.” 32 The Commission directed NERC
to “ensure the reliability standard contains appropriate mechanisms for ensuring the benchmark
event reflects up-to-date meteorological data.” 33 The Commission further directed that NERC
develop the benchmark events for extreme heat and cold weather events through the Reliability

28
29
30
31
32
33

Id. at P 27.
Id. at P 35.
Id. at P 36.
Id. at P 37.
Id. at P 38.
Id. at P 40.

11

Standards development process, along with the process for defining mechanisms to periodically
update these events. 34
With respect to benchmark planning cases, the Commission directed NERC to include “the
framework and criteria that responsible entities shall use to develop from the relevant benchmark
event

planning

cases

to

represent

potential

weather-related

contingencies

(e.g.,

concurrent/correlated generation and transmission outages, derates) and expected future conditions
of the system such as changes in load, transfers, and generation resource mix, and impacts on
generators sensitive to extreme heat or cold, due to the weather conditions indicated in the
benchmark events.” 35 The Commission stated that benchmark planning cases “should be
developed by registered entities such as large planning coordinators, or groups of planning
coordinators, with the capability of planning on a regional scope.” 36
With respect to the study of wide-area impacts of extreme heat and extreme cold weather,
the Commission directed NERC to “clearly describe the process that an entity must use to define
the wide-area boundaries,” declining to endorse any one specific approach in the final rule. 37 The
Commission directed NERC to require the study of concurrent/correlated generator and
transmission outages due to the extreme heat or extreme cold benchmark events, with NERC to
develop the framework and criteria for entities to use in representing potential weather-related
contingencies in their planning cases. 38 The Commission directed NERC to require entities to
perform both steady state and transient stability (dynamic) analyses in planning studies, 39 and to

34
35
36
37
38
39

Id. at PP 58-59.
Id. at P 39.
Id. at P 60.
Id. at P 50.
Id. at PP 88, 91-92.
Id. at P 111.

12

define a set of contingencies that entities will be required to consider when conducting their
studies. 40 The Commission directed that entities model load response in their planning area, and
for NERC to determine whether additional steps are needed to ensure that the impacts of demand
load response are accurately modeled. 41 The Commission directed NERC to require the use of
sensitivity cases to demonstrate the impact of changes to the assumptions used in the benchmark
planning case, which consideration to conditions that vary with temperature such as load,
generation, and system transfers. 42 The Commission further directed NERC to require the use of
planning methods that “ensure adequate consideration of the broad characteristics of extreme heat
and cold weather conditions,” and to consider whether probabilistic elements could be
incorporated. 43
The Commission directed NERC to ensure entities share information with the responsible
planning entity as needed to develop benchmark planning cases and conduct wide-area studies,
and for the planning entity to share the study results with affected Transmission Operators,
Transmission Owners, Generator Owners, and other functional entities with a reliability need for
the studies. 44
With respect to corrective measures, the Commission directed NERC to require entities to
develop Corrective Action Plans for specified instances when performance standards are not met
– i.e., when studies show that an event would result in cascading outages, uncontrolled separation,

Id. at P 112-113.
Id. at PP 116-117.
42
Id. at PP 124-125.
43
Id. at P 134. The Commission directed NERC to describe in its petition the barriers preventing
implementation of probabilistic elements that were identified but determined to be infeasible for including in the
proposed Reliability Standard at this time. Id. at P 138.
44
Id. at PP 72, 77.
40
41

13

or instability. 45 Noting jurisdictional and resource adequacy considerations, the Commission
directed NERC to require entities to share their Corrective Action Plans with, and solicit feedback
from, applicable regulatory authorities or governing bodies responsible for retail electric service
issues; if such Corrective Action Plans include non-consequential load loss, the Corrective Action
Plans should also identify corrective actions which, if approved and implemented, would avoid
the use of load shedding. 46
With respect to implementation, the Commission directed that NERC propose an
implementation timeline for its proposed new or revised Reliability Standard that has
implementation beginning no later than 12 months following the effective date of the
Commission’s order approving the standard. 47
V.

JUSTIFICATION FOR APPROVAL: PROPOSED RELIABILITY STANDARD
TPL-008-1
Proposed Reliability Standard TPL-008-1 – Transmission System Planning Performance

Requirements for Extreme Temperature Events is a new Reliability Standard, developed in
response to Order No. 896, focused specifically on improving how Planning Coordinators and
Transmission Planners plan for the potential impacts of extreme heat and extreme cold temperature
events on the reliable operation of the Bulk-Power System. The proposed Reliability Standard
consists of a framework, consisting of 11 requirements, for the performance of periodic studies
assessing the wide-area impacts of extreme heat and extreme cold temperature events on the BulkPower System. These periodic studies are referred to as Extreme Temperature Assessments.
Proposed Reliability Standard TPL-008-1 would require planning entities in a planning zone,

45
46
47

Id.at PP 152-153, 157.
Id. at P 165, 167.
Id. at P 188, 193.

14

defined in Attachment 1 to the standard, to coordinate with each other on the development of
Extreme Temperature Assessments. The proposed standard contains requirements addressing
coordination, requirements addressing the creation of benchmark temperature events and planning
cases based on the benchmark temperature events, requirements for steady state and transient
stability analyses including sensitivity cases, requirements for entities to develop Corrective
Action Plans in specified instances where system performance requirements are not met, and
requirements for the sharing of study information and any Corrective Action Plans developed to
address system performance issues.
As discussed more fully below, proposed Reliability Standard TPL-008-1 addresses a
reliability gap in the currently effective Transmission Planning Reliability Standards, is responsive
to the Commission’s directives in Order No. 896, and would advance the reliability of the BulkPower System by improving how entities plan for the impacts of extreme temperature events on
their systems.
As explained in Exhibit G, NERC developed the proposed Reliability Standard using
NERC’s standard development process. This process included multiple public comment and ballot
periods. The NERC Board of Trustees adopted the proposed Reliability Standard on December 10,
2024.
In this section, NERC provides an overview of proposed Reliability Standard TPL-008-1,
including the proposed definition of Extreme Temperature Assessment, the title, purpose, and
applicability of the proposed standard, and supporting justification for each of the proposed
requirements. This section also describes the framework in the proposed standard for ensuring
wide-area coordination for planning studies, consistent with Order No. 896. Additional
information may be found in the Technical Rationale, included as Exhibit E to this filing, as well

15

as the Summary of Development History and Complete Record of Development, included as
Exhibit G.
A.

Proposed Glossary Term: Extreme Temperature Assessment

Proposed Reliability Standard TPL-008-1 contains a new defined term, Extreme
Temperature Assessment, to refer to the extreme heat and extreme cold planning studies required
under the standard. The proposed definition of this term is as follows:
Extreme Temperature Assessment – Documented evaluation of future Bulk Electric
System performance for extreme heat and extreme cold benchmark temperature events.
The proposed definition is intended to make the requirements of the proposed standard
easier to read and understand. NERC proposes to include this term in the Glossary of Terms
used in NERC Reliability Standards.
B.

Title, Purpose, and Applicability

The title of proposed Reliability Standard TPL-008-1 is Transmission System Planning
Performance Requirements for Extreme Temperature Events. The stated purpose of the standard
is: “Establish Transmission system planning performance requirements to develop a Bulk Power
System (BPS) that will operate reliably during extreme heat and extreme cold temperature events.”
Proposed Reliability Standard TPL-008-1 is applicable to Transmission Planners and Planning
Coordinators, consistent with the functional entity applicability of other Transmission Planning
(TPL) Reliability Standards.
C.

A New Framework for Wide-Area Coordination in the Performance of
Extreme Temperature Assessments

Proposed Reliability Standard TPL-008-1 contains a framework unique among the
transmission planning Reliability Standards for the regional coordination of transmission planning
studies addressing extreme heat and extreme cold temperature events. In Order No. 896, the
Commission directed NERC to develop a new or revised Reliability Standard “that addresses
16

concerns pertaining to transmission system planning for extreme heat and cold weather events that
impact the Reliable Operation of the Bulk-Power System.” 48 Noting that the impacts of extreme
heat and cold weather events can be widespread, causing loss of generation and transmission
constraints within and across regions, the Commission directed that NERC consider these widearea impacts in developing a responsive standard. 49 Further, the Commission directed NERC to
ensure that studies would be undertaken by entities with the “capability of planning on a regional
scope.”

50

Proposed Reliability Standard TPL-008-1 addresses these directives through a

framework by which Planning Coordinators in a predefined zone are required to coordinate on the
identification of appropriate benchmark temperature events for the zone and the implementation
of mutually agreeable processes for developing planning and sensitivity cases based on those
benchmark temperature events.
Proposed Reliability Standard TPL-008-1 contains three requirements addressing widearea coordination in the performance of the Extreme Temperature Assessment: proposed
Requirement R2, addressing the identification of benchmark temperature events; proposed
Requirement R3, addressing processes for developing benchmark planning cases based on the
benchmark temperature events and sensitivity cases to demonstrate the impact of changes to the
basic assumptions used in the benchmark planning cases; and proposed Requirement R4,
addressing the development of benchmark planning cases using the coordinated processes.
Attachment 1 to proposed Reliability Standard TPL-008-1 would define the zones, and thereby the
Planning Coordinators, that must work with each other to select the appropriate benchmark events

48
49
50

Order No. 896 at P 1.
See id. at PP 41-50.
Id. at P 60.

17

and implement processes for coordinating the development of planning cases and sensitivity cases
for the Extreme Temperature Assessment within that zone.
Collectively, proposed Reliability Standard TPL-008-1 Requirements R2-R4 and
Attachment 1 are responsive to the Commission’s directives in Order No. 896 relating to widearea studies of extreme heat and extreme cold temperature events. In Order No. 896, the
Commission directed NERC to require that transmission planning studies under the new or revised
Reliability Standard consider the wide-area impacts of extreme heat and cold weather, with the
standard describing the process to define the wide-area boundaries. 51 Proposed Reliability
Standard TPL-008-1 Attachment 1 is responsive to these directives in that it defines the wide-area
boundaries and helps to ensure that benchmark planning cases are developed on a regional scope,
with consideration to the wide-area impacts of extreme heat and cold weather. Additional
discussion of how the drafting team developed these zones is provided in Section V.E.2, below,
and in the Technical Rationale, included as Exhibit E. While the zone boundaries defined in
Attachment 1 would require some Planning Coordinators to coordinate with many other Planning
Coordinators, the industry has demonstrated, through various working groups and organizations,
that it is capable of cooperating to build models that represent large areas.
Proposed Reliability Standard TPL-008-1 Requirements R2-R4 and Attachment 1 are also
responsive to the Commission’s directive that benchmark planning cases be developed by entities
capable of planning on a regional scope. 52 The Planning Coordinator, as “the responsible entity
that coordinates and integrates transmission Facilities and service plans, resource plans, and
Protection Systems,” would coordinate with other Planning Coordinators in a zone to identify

51
52

Id. at P 50.
Id. at P 60.

18

benchmark temperature events and implement a process for developing benchmark planning cases
and sensitivity cases for the Extreme Temperature Assessment. The identification of joint and
individual responsibilities in Requirement R1 provides a measure of flexibility for Planning
Coordinators and Transmission Planners 53 to agree on a distribution of responsibilities. Thus,
while Planning Coordinators are responsible for implementing the planning case development
process in Requirement R3, Transmission Planners may be responsible for providing data and
completing the case development according to that process under Requirement R4. Acting
together, these functional entities would have a wide-area view of the Bulk-Power System and the
ability to conduct long-term planning studies across a wide geographic area, consistent with
paragraph 61 of Order No. 896. Further, these entities would have “the planning tools, expertise,
processes, and procedures to develop benchmark planning cases and analyze extreme weather
events in the long-term planning horizon.” 54
Additional discussion of the proposed requirements comprising this coordination
framework is provided in the requirement-by-requirement discussion below.
D.

Requirement R1

Proposed Reliability Standard TPL-008-1 Requirement R1 is a foundational requirement
under which Planning Coordinators and Transmission Planners would identify which entity would
be responsible for performing the tasks needed to complete the Extreme Temperature Assessment
so that an Extreme Temperature Assessment is completed at least once every five years. Proposed
Requirement R1 would provide as follows:
R1.

Each Planning Coordinator shall identify, in conjunction with its Transmission
Planner(s), each entity’s individual and joint responsibilities for completing the

The NERC Glossary defines the Transmission Planner as “The entity that develops a long-term (generally
one year and beyond) plan for the reliability (adequacy) of the interconnected bulk electric transmission systems within
its portion of the Planning Authority [or Planning Coordinator] area.”
54
Order No. 896 at P 61.
53

19

Extreme Temperature Assessment, which shall include each of the responsibilities
described in Requirements R2 through R11. Each responsible entity shall complete
its responsibilities such that the Extreme Temperature Assessment is completed at
least once every five calendar years.
Proposed Requirement R1 is similar to Reliability Standard TPL-001-5.1 Requirement R7
and TPL-007-4 Requirement R1, each of which address the Planning Coordinator working with
its Transmission Planner(s) to identify individual and joint responsibilities for planning studies.
As discussed more fully below, requirements for the selection of benchmark temperature events
and processes for developing benchmark planning cases across a zone are the responsibility of the
Planning Coordinators within that zone; however, Requirement R1 provides a measure of
flexibility for Planning Coordinators and Transmission Planners to agree on a division of
responsibilities for completing the remaining requirements.
In determining that the Extreme Temperature Assessment should be completed at least
once every five calendar years, the drafting team considered the significant level of data collection
and coordination that would be required between the Planning Coordinator(s) and Transmission
Planner(s) to coordinate, prepare, perform, and document the study results and to develop any
necessary Corrective Action Plans. A similar five-year timeframe is prescribed for the GMD
Vulnerability Assessments required under Reliability Standard TPL-007-4. Planning entities may
conduct more frequent Extreme Temperature Assessments; however, at least one Extreme
Temperature Assessment must be completed at least once every five years.
E.

Requirement R2

Proposed Reliability Standard TPL-008-1 Requirement R2 addresses the selection of
benchmark temperature events to be used for completing the Extreme Temperature Assessment.
Proposed Requirement R2 would provide as follows:
R2.

Each Planning Coordinator shall identify the zone(s) to which the Planning
Coordinator belongs to under Attachment 1 and shall coordinate with all Planning
20

Coordinators within each of its identified zone(s), to identify one common extreme
heat benchmark temperature event and one common extreme cold benchmark
temperature event for each of its identified zone(s) when completing the Extreme
Temperature Assessment. The benchmark temperature events shall be obtained
from the benchmark library maintained by the ERO or developed by the Planning
Coordinators. Each benchmark temperature event identified by the Planning
Coordinators shall:
2.1.

Consider no less than a 40-year period of temperature data ending no more
than five years prior to the time the benchmark temperature events are
selected; and

2.2.

Represent one of the 20 most extreme temperature conditions based on the
three-day rolling average of daily maximum (heat) or daily minimum (cold)
temperature across the zone.

Proposed Requirement R2 would require each Planning Coordinator to coordinate with
other Planning Coordinators within the predefined planning zones specified in Attachment 1 in the
selection of benchmark temperature events to be used for Extreme Temperature Assessments.
These benchmark temperature events would be used for the creation of benchmark planning cases
used to complete the Extreme Temperature Assessment. As explained below, the predefined zones
in Attachment 1 were developed with a view toward studying the wide-area impacts of extreme
weather, with consideration to regional differences in climate and weather patterns along with
other relevant factors. Consistent with paragraphs 35-38 of Order No. 896, proposed Requirement
R2 would ensure that all Planning Coordinators within a zone are using a consistent benchmark
temperature event, that the benchmark temperature event would reflect regional differences in
climate and weather patterns, and that the studied benchmark temperature events would be of an
appropriate severity so that the Extreme Temperature Assessments may advance transmission
system reliability during future extreme heat and extreme cold temperature conditions.
1. Benchmark Temperature Event Criteria
Extreme hot and cold temperatures experienced during benchmark temperature events are
assumed to be outside the ranges used as the basis of planning cases studied under Reliability
21

Standard TPL-001-5.1. Since temperature levels and associated weather conditions affect load
levels, generation performance, and transfer levels, the selection of benchmark temperature events
is critical to ensuring the Extreme Temperature Assessment appropriately evaluates probable
system conditions.
Since any region can experience temperatures that are higher or lower than normal,
Planning Coordinators within the same zone must coordinate to select one common temperature
event that includes hotter temperature assumptions and one common temperature event that
includes colder temperature assumptions. While it is understood that, for example, one region may
typically experience hotter summers and milder winters than another region, both a hotter than
average summer and a colder than average winter could result in reliability concerns. Therefore,
proposed Reliability Standard TPL-008-1 requires entities to study one common case specific to
extreme heat conditions and one common case specific to extreme cold conditions for the Extreme
Temperature Assessment. By selecting common events, Planning Coordinators would ensure that
extreme temperatures are studied over the entire zone.
The drafting team determined that the extreme heat and extreme cold temperatures selected
must have a verified statistical basis based on weather data from credible sources. In drafting this
requirement, the drafting team considered the Commission’s direction in paragraph 36 of Order
No. 896 to consider approaches for developing benchmarks of an appropriate severity. 55 The
drafting team has identified several key features that are used to determine when an extreme heat
or extreme cold temperature event would constitute a valid benchmark temperature event for the
purposes of the standard. Specifically, benchmark temperature events must: (1) consider no less

See Order No. 896 at P 36 (“As recommended by commenters, NERC should consider the examples of
approaches for defining benchmark events identified in the NOPR (e.g., the use of projected frequency or probability
distribution). NERC may also consider other approaches that achieve the objectives outlined in this final rule.”).

55

22

than 40 years of temperature data; (2) use data ending no more than five years prior to the time
benchmark temperature events are selected; and (3) represent one of the worst 20 extreme
temperature conditions within the zone.
To support the identification of these criteria, NERC analyzed historical meteorological
data over a 43-year period. 56 Over time, as tools and methods mature, NERC may expand its
benchmark temperature event library or revise the TPL-008 benchmark temperature criteria to
cover future meteorological projections or other factors that are identified that may advance
accurate system planning. 57 However, historical event data analysis, focusing on historical
extremes, represents an acceptable and technically justified basis for developing benchmark
temperature events in proposed Reliability Standard TPL-008-1 in accordance with Order No. 896.
The requirement to consider no less than 40 years of temperature data was established
based on the observation that many of the worst events identified in various regions of North
America occurred in the 1980s and 1990s. For example, preliminary data indicated that the five
worst extreme cold temperature events in the PJM region over the last 43 years occurred between
1983 and 1994. Similar results were seen in other regions for both extreme heat and extreme cold
temperature events. Thus, the drafting team determined that a minimum of 40 years of temperature
data should be used to ensure more extreme events would not be excluded by using a shorter
duration of temperature data.
The requirement to use data that ends no more than five years prior ensures that the data
would capture more recent extreme temperature events and would help ensure that the benchmark

For more information on this analysis, see draft ERO Enterprise Process for TPL-008-1 Benchmark
Weather Event Development and Maintenance document, Exhibit G (Summary of Development History and
Complete Record of Development) at item 82.
57
For example, NERC’s annual Long-Term Reliability Assessments may provide additional insights for more
accurate modeling of future extreme weather conditions.
56

23

temperature events are updated over time. This requirement is responsive to paragraph 40 of Order
No. 896, in which the Commission directed NERC to include mechanisms to periodically update
benchmark temperature events. 58 To the extent future years bring more extreme temperature
events, those events would be captured in the updated data.
The requirement to use one of the worst 20 temperature events within the zone is intended
to ensure that entities have a sufficient collection of temperature events to review and identify for
further studies. While extreme events have become more common in recent years, the historical
data did not provide many extreme events over a three-day rolling average over 40 years. The
drafting team determined that it is important for an entity to be able to evaluate events that
happened over 40 years, as some of the events may not have been as extreme compared to other
events, and that identifying a fewer number of events (e.g., 10 or fewer) may not provide a
sufficiently complete picture of wide-area extreme conditions. 59
Temperature events are ranked by computing the three-day rolling average of daily
maximum temperatures (for extreme heat) or daily minimum temperatures (for extreme cold).
Rather than isolating single hours of extreme weather, the rolling three-day average of minimum
and maximum daily temperatures were chosen to represent prolonged periods of extreme weather.
The three-day averaging period is centered on every day in the data and identifies the average
minimum and maximum temperature from the day before, day of, and day after. The output of this
process develops a dataset of multi-day minimum and maximum temperatures to filter out
See Order No. 896 at P 40.
Initially, the drafting team considered using a 95th percentile statistical basis for identifying extreme
benchmark temperature events. Over a 40-year period, this would equate to 243 unique three-day periods, the majority
of which would not reflect the most significant temperature events. Additionally, the worst case does not occur at the
same time in each zone. Analysis of the data for the 40 coldest and 40 warmest maximum temperatures for each zone
was performed; it was determined that, after refinement and elimination of duplicate or overlapping periods, a list of
20 events would capture the events that are the worst case for a region as well as those that had impacts across multiple
regions simultaneously. The drafting team noted that, in some years, more than one extreme event occurred; therefore,
the worst 20 events would not necessarily be the same as the worst event from 20 unique years.

58
59

24

individual days of extreme heat or cold under the assumption that the Bulk-Power System is more
challenged by sustained periods of extreme heat or cold due to cumulative effects on increasing
demand and generator outages.
NERC, as the Electric Reliability Organization, would maintain a library of benchmark
temperature events to provide responsible entities with vetted events that meet the criteria of
Requirement R2. The Draft ERO Enterprise Process for TPL-008-1 Benchmark Weather Event
Development and Maintenance document describes how NERC would develop and maintain the
benchmark temperature events in its library. 60 While selection of events from the ERO’s library
would assure Planning Coordinators they are selecting valid events, proposed Requirement R2
would allow Planning Coordinators flexibility to collect temperature data and identify benchmark
temperature events through their own processes. Planning Coordinators that elect to develop their
own benchmark temperature events would be responsible for ensuring the input temperature data
and selected benchmark temperature events meet the criteria of proposed Requirement R2.
Additionally, because proposed Requirement R2 would require Planning Coordinators within a
zone to coordinate in the selection of the benchmark temperature events, the process used to
identify these events must be agreeable to those Planning Coordinators. Thus, while proposed
Requirement R2 would provide some flexibility in the selection of benchmark temperature events,
it addresses fully the Commission’s underlying concern in Order No. 896 that planning entities
acting on a regional scope study consistent benchmark temperature events. 61

See draft ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and
Maintenance document, Exhibit G (Summary of Development History and Complete Record of Development) at
item 82.
61
See Order No. 896 at P 37 (“Because the impact of most extreme heat and cold events spans beyond the
footprints of individual planning entities, it is important that all responsible entities likely to be impacted by the same
extreme weather events use consistent benchmark events. Doing so is important to ensuring that neighboring planning
regions are assuming similar weather conditions and are able to coordinate their assumptions accordingly. . .”).
60

25

2. Attachment 1: Extreme Temperature Assessment Zones
Proposed Reliability Standard TPL-008-1 Attachment 1 defines twenty Extreme
Temperature Assessment planning zones across the U.S. and Canada. As noted above, Planning
Coordinators within each zone must coordinate with each other on selecting benchmark
temperature events and performing other tasks to complete the Extreme Temperature Assessment.
The following map depicts the approximate boundaries of the Attachment 1 Extreme
Temperature Assessment planning zones:
Figure 1: TPL-008-1 Attachment 1 Extreme Temperature Assessment Planning Zones

In defining the zones to be used for wide-area studies in the Extreme Temperature
Assessment, the drafting team considered the Commission’s directive in Order No. 896 that
transmission planning studies consider the wide-area impacts of extreme heat and extreme cold
weather. Proposed Reliability Standard TPL-008-1 Attachment 1 would split the North American
Bulk-Power System into several distinct zones that have similar electric power system properties
26

and similar weather or climatological patterns. In developing these zones, the drafting team
considered Balancing Authority boundaries, the work of technical experts retained by NERC to
analyze weather data and prepare benchmark temperature events for study, as well as comments
submitted throughout the standard development process.
In proposed Attachment 1, Balancing Authorities with large areas of jurisdiction,
exclusively Independent System Operators and Regional Transmission Organizations, would be
assigned their own weather zones. In geographical areas comprised of multiple Balancing
Authority Areas, generalized weather zones were created to best represent zonal weather patterns.
The zones depicted in Attachment 1 are either aligned with existing Planning Coordinator
boundaries or boundaries of a group of Planning Coordinators with similar weather patterns.
Consistent with comments received during the standard development process, the drafting team
considered the presence of transmission constraints (or the lack of transmission) between areas in
developing the final zones, as well as other comments on the appropriateness of the defined zones
for extreme weather planning studies. 62 Based on consideration of all relevant factors, the drafting
team determined the zones depicted in Attachment 1 would represent reasonable boundaries that
balance the need for studies to cover large regions with similar weather patterns with the need for
a manageable level of coordination for the entities responsible for carrying out the studies.
For the reasons stated above, proposed Requirement R2 addresses Commission directives
regarding the development of extreme heat and extreme cold benchmark temperature events in

For example, stakeholder concerns on an earlier version of the proposed map included concerns that the map
would have grouped regions that may have been too large to provide for meaningful analysis, would have grouped
regions with different historical extreme weather patterns, or would have grouped regions that do not typically transfer
significant power to each other during an extreme temperature event. See Draft 3 Comment Report (Oct. 2024), Exhibit
G Summary of Development and Complete Record of Development, at item 51 (responses to Question 1).

62

27

Order No. 896. The Commission’s directives regarding developing planning cases based on
benchmark temperature events are addressed in proposed Requirement R3, as discussed below.
F.

Requirement R3

Proposed Reliability Standard TPL-008-1 Requirement R3 establishes the framework and
criteria for the development of benchmark planning cases for the Extreme Temperature
Assessment. Proposed Requirement R3 would provide as follows:
R3.

Each Planning Coordinator shall coordinate with all Planning Coordinators within
each of its zone(s) identified in Requirement R2, to implement a process for
developing benchmark planning cases for the Extreme Temperature Assessment
that represent the benchmark temperature events selected in Requirement R2 and
sensitivity cases to demonstrate the impact of changes to the basic assumptions used
in the benchmark planning cases. This process shall include the following:
3.1.

Selection of System models within the Long-Term Transmission Planning
Horizon to form the basis for the benchmark planning cases.

3.2.

Forecasted seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers within the zone.

3.3.

Assumed seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers in areas outside the zone, as needed.

3.4.

Identification of changes to at least one of the following conditions for
sensitivity cases: generation, real and reactive forecasted Load, or transfers.

Proposed Requirement R3 aligns with the Commission’s directives in Order No. 896,
emphasizing the importance of coordinating the development of benchmark planning cases and
sensitivity cases amongst planning entities within a zone, where the scope of extreme temperature
event studies will likely cover large geographical areas exceeding smaller individual planning
areas. 63 Proposed Requirement R3 also addresses, in whole or in part, several other Commission
directives related to coordination and the development of benchmark planning and sensitivity
cases, as discussed more fully below.

63

See, e.g., Order No. 896 at PP 60-62.

28

Recognizing that the scope of effective coordination may vary across the zones, proposed
Requirement R3 would require each Planning Coordinator to coordinate with all Planning
Coordinators within a zone to implement a process for the development of benchmark planning
cases and sensitivity cases. Planning Coordinators within a zone must coordinate to implement a
process that results in the development of benchmark planning cases that represent the benchmark
temperature events selected in accordance with Requirement R2, and sensitivity cases that
demonstrate the impact of changes to the basic assumptions used in the benchmark planning cases.
This process requires several components, outlined in the sub-requirements of Requirement R3.
First, Requirement R3 Part 3.1 would require Planning Coordinators within a zone to select
System models which form the basis for developing the benchmark planning cases. These models
must represent one of the years in the Long-Term Transmission Planning Horizon. 64 Planning
Coordinators would also need to ensure models include stability modeling data to provide for the
performance of stability analysis later in the process. The drafting team anticipated that Planning
Coordinators would likely use a summer peak model as the starting point for the extreme heat
benchmark temperature event and a winter peak model as the starting point for the extreme cold
benchmark temperature event.
Second, Requirement R3 Part 3.2 would require that Planning Coordinators within a zone
provide forecasted data for their area within the zone that represents the benchmark temperature
events selected in accordance with Requirement R2. Each Planning Coordinator must provide data
for its area within the zone that represents seasonal and temperature adjustments for Load,

The NERC Glossary defines the Long-Term Transmission Planning Horizon as the “Transmission planning
period that covers years six through ten or beyond when required to accommodate any known longer lead time projects
that may take longer than ten years to complete.”

64

29

generation, Transmission, and transfers. The provided data should be used to update the starting
point models to reflect the selected benchmark temperature events.
Third, Requirement R3 Part 3.3 would allow Planning Coordinators to agree on
assumptions for seasonal and temperature adjustments for Load, generation, Transmission, and
transfers in areas outside of the zone. As a sub-requirement of Requirement R3, these assumptions
must be coordinated among Planning Coordinators in the zone, as needed. As an example,
Planning Coordinators within the zone may identify the need for imported power during a
benchmark temperature event. The Planning Coordinators may evaluate historical import
availability and assume imports from an area outside of the zone are reasonable and should be
modeled.
Fourth, and lastly, Requirement R3 Part 3.4 would require Planning Coordinators to
coordinate and identify changes to generation, real and reactive forecasted Load, or transfers that
should be reflected in sensitivity cases. Sensitivity cases are intended to demonstrate the impact of
changes to the basic assumptions used in the benchmark planning cases; Requirement R3 Part 3.4
would ensure Planning Coordinators are cooperating to identify changes that would sufficiently
alter the assumptions reflected in the benchmark planning cases. For example, Planning
Coordinators that identified an import external source to the zone for a benchmark planning case
could elect to alter the source of that import in the sensitivity case.
Proposed Requirement R3 addresses in whole or in part several Commission directives
from Order No. 896 related to the development of benchmark temperature event planning cases
and sensitivity cases, as discussed below.

30

1. Consideration of Directive: Order No. 896 paragraph 39 65
Proposed Requirement R3 addresses in part the Commission’s directive in paragraph 39 to
provide a “framework and criteria” for developing planning cases from the benchmark temperature
events. Proposed Requirement R3 provides that Planning Coordinators shall develop benchmark
planning cases from the selected benchmark temperature events to represent potential weatherrelated contingencies and expected future conditions of the system such as changes in load,
transfers, and generation resource mix, and impacts on generators sensitive to extreme heat or cold.
Requirement R4, discussed in Section V.G below, also addresses this directive, by
requiring the responsible entity to develop benchmark planning cases and sensitivity cases for
performing the Extreme Temperature Assessment which reflects System conditions from the
selected benchmark events.
2. Consideration of Directive: Order No. 896 paragraph 72 66
Proposed Requirement R3 addresses in part the Commission’s directive in paragraph 72
regarding sharing of information needed to complete studies. Under proposed Requirement R3,
Planning Coordinators shall implement a process for developing benchmark planning and
sensitivity cases that would by its nature require the responsible entities to share system
information as needed to develop benchmark planning cases and conduct wide-area studies.

Order No. 896 at P 39 (directing NERC to “include in the Reliability Standard the framework and criteria
that responsible entities shall use to develop from the relevant benchmark event planning cases to represent potential
weather-related contingencies (e.g., concurrent/correlated generation and transmission outages, derates) and expected
future conditions of the system such as changes in load, transfers, and generation resource mix, and impacts on
generators sensitive to extreme heat or cold, due to the weather conditions indicated in the benchmark events. . .” See
also general discussion, id. at P 35 (“[W]e direct NERC to: (1) develop extreme heat and cold weather benchmark
events, and (2) require the development of benchmark planning cases based on identified benchmark events.”).
66
Order No. 896 at P 72 (directing NERC “to require functional entities to share with the entities responsible
for developing benchmark planning cases and conducting wide-area studies the system information necessary to
develop benchmark planning cases and conduct wide-area studies.”).
65

31

Requirements R4 and R11, discussed in subsequent sections, also address parts of this
directive related to data sharing among responsible entities and with reliability entities.
3. Consideration of Directive: Order No. 896 paragraph 76 67
Proposed Requirement R3 addresses the Commission’s directive in paragraph 76 regarding
requirements for wide-area coordination in planning studies. Proposed Requirement R3 addresses
requirements for wide-area coordination in the development of benchmark temperature event
planning cases and sensitivity cases among planning Coordinators in each planning zone, with the
zones defined in Attachment 1.
4. Consideration of Directives: Order No. 896 paragraphs 88 and 92 68
Proposed Requirement R3 addresses the Commission’s directives in paragraph 88 and 92
regarding the study of concurrent/correlated generator and transmission outages due to extreme
heat and cold events. Proposed Requirement R3 would require the study of concurrent/correlated
generator and transmission outages due to extreme heat and cold events in benchmark events, with
contingencies identified based on similar contingencies that occurred in recent extreme weather
events or expected in future events. Under proposed Requirement R3 Part 3.2, the benchmark
planning case development process must include forecasted seasonal and temperature dependent
adjustments for Load, generation, Transmission, and transfers within the zone. Requirement R4,
discussed in Section V.G, also addresses this directive, by specifying the data necessary to build
the benchmark planning cases must be provided via MOD-032, supplemented by other sources as

Order No. 896 at P 76 (“[W]e…direct NERC to address the requirement for wide-area coordination through
the standards development process, giving due consideration to relevant factors identified by commenters in this
proceeding.”).
68
See id. at P 88 (“[W]e direct NERC to require under the new or revised Reliability Standard the study of
concurrent/correlated generator and transmission outages due to extreme heat and cold events in benchmark events as
described in more detail below.”) and P 92 (“These contingencies (i.e., correlated/concurrent, temperature sensitive
outages, and derates) shall be identified based on similar contingencies that occurred in recent extreme weather events
or expected to occur in future forecasted events.”).
67

32

needed. Any concurrent/correlated generator and transmission outages due to extreme heat and
cold events in benchmark temperature events should be reflected in the model data and thus
represented in the initial conditions of the benchmark planning cases.
5. Consideration of Directives: Order No. 896 paragraphs 124 and 125 69
Proposed Requirement R3 addresses the Commission’s directives and guidance in
paragraphs 124 and 125 requiring the use of sensitivity cases to demonstrate the impact of changes
to the assumptions used in the benchmark planning case. Proposed Requirement R3 would require
all Planning Coordinators within the same zone, defined in Attachment 1 to the proposed standard,
to coordinate to implement a process for developing benchmark planning cases and sensitivity
cases. Sensitivity cases are used to demonstrate the impact of changes to the basic assumptions
used in the benchmark planning cases. Under Requirement R3 Part 3.4, Planning Coordinators
must include provisions in the case development process to identify changes to generation, real
and reactive forecasted Load, and/or transfers to develop sensitivity cases.
The identification of changes for sensitivity cases within the coordinated process of
Requirement R3 addresses the Commission’s direction in paragraph 125 that the proposed
standard should preclude responsible entities from determining sensitivities alone. However,
responsible entities would retain the flexibility to conduct additional sensitivity studies they would
find relevant to their planning areas.

Order No. 896 at P 124 (directing NERC to “to require the use of sensitivity cases to demonstrate the impact
of changes to the assumptions used in the benchmark planning case” and “to define during the Reliability Standard
development process a baseline set of sensitivities for the new or modified Reliability Standard. While we do not
require the inclusion of any specific sensitivity in this final rule, NERC should consider including conditions that vary
with temperature such as load, generation, and system transfers.”).
Id. at P 125 (stating, “We do not agree ... that responsible entities alone should determine the sensitivity cases
that must be considered in the responsible entity’s study. … We…believe that responsible entities should be free to
study additional sensitivities relevant to their planning areas…cooperation will be necessary between responsible
entities conducting extreme heat and extreme cold weather studies and other registered entities within their extreme
weather study footprints to ensure the selection of appropriate sensitivities.”).

69

33

G.

Requirement R4

Proposed Reliability Standard TPL-008-1 Requirement R4 establishes requirements for
developing benchmark planning cases and sensitivity cases to include in the Extreme Temperature
Assessment.
Proposed Requirement R4 would provide as follows:
R4.

Each responsible entity, as identified in Requirement R1, shall use the process
developed in Requirement R3 and data consistent with that provided in accordance
with the MOD-032 standard, supplemented by other sources as needed, to develop
the following and establish category P0 as the normal System condition in Table 1:
4.1.

One common extreme heat and one common extreme cold benchmark
planning case.

4.2.

One common extreme heat and one common extreme cold sensitivity case.

Proposed Requirement R4, like proposed Requirement R3 discussed in the previous
section, aligns with the Commission’s directives in Order No. 896 emphasizing the importance of
coordinating the development of benchmark planning cases and sensitivity cases within a zone,
where the scope of extreme temperature event studies will likely cover large geographical areas
exceeding smaller individual planning areas. 70 Proposed Requirement R4 also addresses several
other Commission directives related to coordination and the development of benchmark planning
and sensitivity cases, as discussed more fully below and in the discussion of proposed Requirement
R3 in the preceding section.
Proposed Requirement R4 would require the responsible entity, which may be the Planning
Coordinator or Transmission Planner as identified in Requirement R1, to use the process
implemented among the zone Planning Coordinators in Requirement R3 and data consistent with
Reliability Standard MOD-032, supplemented by other sources as needed, for developing
benchmark planning cases that represent System conditions based on selected benchmark
70

See, e.g., Order No. 896 at PP 60-62.

34

temperature events. Proposed Reliability Standard TPL-008-1 Requirement R4 is consistent with
Reliability Standard TPL-001-5.1 in that it cross-references Reliability Standard MOD-032;
Reliability Standard MOD-032 establishes consistent modeling data requirements and reporting
procedures for the development of planning horizon cases necessary to support analysis of the
reliability of the interconnected system. Proposed TPL-008-1 Requirement R4 is also consistent
with Reliability Standard TPL-001-5.1 in acknowledging that data from other sources may be
required to supplement the data collected through Reliability Standard MOD-032 procedures.
Proposed Requirement R4 would require entities to use the coordination process developed
in accordance with proposed Requirement R3 to develop at a minimum the following four cases:
•

One common extreme heat benchmark planning case (Requirement R4 Part 4.1),

•

One common extreme cold benchmark planning case (Requirement R4 Part 4.1),

•

One common extreme heat sensitivity case (Requirement R4 Part 4.2), and

•

One common extreme cold sensitivity case (Requirement R4 Part 4.2).

At the completion of the case development process implemented in accordance with
Requirement R3, and executed in Requirement R4, responsible entities would have at a minimum
the four cases listed above. Category P0 would be established as the normal System condition in
Table 1 for each case. As discussed in the previous section, proposed Requirement R3 would allow
Planning Coordinators the flexibility to implement a process that would develop cases for multiple
benchmark temperature events or to develop additional sensitivity cases. Moreover, planning
entities may elect to develop additional cases for their internal use.
Proposed Requirement R4 addresses in whole or in part several Commission directives in
Order No. 896 related to benchmark temperature event planning cases or sensitivity studies, as
discussed below.
35

6. Consideration of Directive: Order No. 896 paragraph 39
As discussed in the previous section, proposed Requirement R3 addresses in part the
Commission’s directive in paragraph 39 to provide the framework and criteria that Planning
Coordinators shall use to develop benchmark planning cases to represent potential weather-related
contingencies and expected future conditions of the system such as changes in load, transfers, and
generation resource mix, and impacts on generators sensitive to extreme heat or cold.
Proposed Requirement R4 also addresses this directive, by requiring the responsible entity
to develop benchmark planning cases and sensitivity cases for performing the Extreme
Temperature Assessment which reflects System conditions from the selected benchmark
temperature events.
7. Consideration of Directive: Order No. 896 paragraph 72
As discussed in the previous section, proposed Requirement R3 addresses in part the
Commission’s directive in paragraph 72 regarding sharing of information needed to complete
studies by specifying that Planning Coordinators shall implement a process for developing
benchmark planning and sensitivity cases; this process would, by its nature, require Planning
Coordinators to share system information as needed to develop benchmark planning cases and
conduct wide-area studies. Proposed Requirement R4 builds on proposed Requirement R3 by
requiring the responsible entities, as identified in Requirement R1, to use the coordination process
implemented in accordance with Requirement R3 and data consistent with that provided in
accordance with the MOD-032 standard, supplemented by other sources as needed, to develop
benchmark planning cases and sensitivity cases.
8. Consideration of Directives: Order No. 896 paragraphs 88 and 92
As discussed in the previous section, proposed Requirement R3 addresses the
Commission’s directives in paragraph 88 and 92 regarding the study of concurrent/correlated
36

generator and transmission outages due to extreme heat and cold events. Proposed Requirement
R4 specifies the data necessary to build the benchmark planning cases must be provided via MOD032, supplemented by other sources as needed. Any concurrent/correlated generator and
transmission outages due to extreme heat and cold events in benchmark temperature events should
be reflected in the model data and thus represented in the initial conditions of the benchmark
planning cases.
9. Consideration of Directives: Order No. 896 paragraphs 116-117 71
Proposed Requirement R4 addresses the Commission’s directives and guidance in
paragraphs 116 and 117 regarding the modeling of demand load response. Proposed Requirement
R4 would require each responsible entity to develop benchmark planning cases and sensitivity
cases using data consistent with that provided in accordance with the MOD-032 standard,
supplemented by other sources as needed. Attachment 1 of the MOD-032 standard requires
responsible entities to provide information requested by the Planning Coordinator or Transmission
Planner that is necessary for modeling purposes, to include demand response data. The drafting
team determined that no further requirement specific to demand response was needed, as the
modeling of demand load response can be implemented through the MOD-032 standard in which
data needed for the base case development can be requested and obtained for development of the
benchmark planning cases and sensitivity cases under proposed TPL-008-1.

Order No. 896 at P 116 (“We . . .direct NERC to require in the new or modified Reliability Standard that
responsible entities model demand load response in their extreme weather event planning area.”).
Id. at P 117 (“[I]n addressing this directive, we expect NERC to determine whether responsible entities will
need to take additional steps to ensure that the impacts of demand load response are accurately modeled in extreme
weather studies, such as by analyzing demand load response as a sensitivity, as is currently the case under Reliability
Standard TPL-001-5.1.”).
71

37

H.

Requirement R5

Proposed Reliability Standard TPL-008-1 Requirement R5 would require each responsible
entity to set the criteria needed for limits that will be used to evaluate System steady state voltage
and post-Contingency voltage deviations for completing the Extreme Temperature Assessment.
Proposed Requirement R5 would provide as follows:
R5.

Each responsible entity, as identified in Requirement R1, shall have criteria for
acceptable System steady state voltage limits and post-Contingency voltage
deviations for completing the Extreme Temperature Assessment.

This requirement would allow for the comparison of the results of the Extreme
Temperature Assessment with the established criteria. Similar requirements are found in other
transmission planning Reliability Standards, including Reliability Standard TPL-001-5.1
(Requirement R5) and Reliability Standard TPL-007-4 (Requirement R3).
I.

Requirement R6

Proposed Reliability Standard TPL-008-1 Requirement R6 would require each responsible
entity to define and document the criteria or methodology used in evaluating the Extreme
Temperature Assessment analysis to identify instability, uncontrolled separation, or Cascading
within an Interconnection. Proposed Requirement R6 would provide as follows:
R6.

Each responsible entity, as identified in Requirement R1, shall define and document
the criteria or methodology to be used in the Extreme Temperature Assessment to
identify instability, uncontrolled separation, or Cascading within an
Interconnection.

Adequate and thorough criteria should be built into the Extreme Temperature Assessment
to help identify instability, uncontrolled separation, and Cascading conditions. The establishment
of these criteria allows for comparison of the results of the Extreme Temperature Assessment with
the established criteria. A similar requirement is found in Reliability Standard TPL-001-5.1
(Requirement R6). The inclusion of the phrase” within an Interconnection” is appropriate because
38

Planning Coordinators and Transmission Planners typically use Interconnection-wide starting
cases prior to making further modifications to reflect the conditions of the benchmark temperature
events and further modifications for the sensitivity cases for steady-state and transient stability
analyses. Analyses that may result in instability, uncontrolled separation, or Cascading typically
are confined within an Interconnection, where generation and transmission Facilities are
interconnected. It is not expected that instability, uncontrolled separation, or Cascading that affect
facilities within an Interconnection would impact other Interconnections, as these systems are
asynchronous systems (i.e., not connecting synchronously).
J.

Requirement R7

Proposed Reliability Standard TPL-008-1 Requirement R7 establishes requirements for
identifying Contingencies for the Extreme Temperature Assessment. Proposed Requirement R7
would provide as follows:
R7.

Each responsible entity, as identified in Requirement R1, shall identify the
Contingencies for each category in Table 1 that are expected to produce more
severe System impacts on its portion of the Bulk Electric System. The rationale for
those Contingencies selected for evaluation shall be available as supporting
information.

Proposed Requirement R7 and the referenced Table 1 address the Commission’s directives
in paragraphs 112-113 of Order No. 896 to define a set of Contingencies that responsible entities
would be required to consider when conducting wide-area studies of extreme heat and cold weather
events. 72

Id. at P 112 (“We . . . direct NERC to define a set of contingencies that responsible entities will be required
to consider when conducting wide-area studies of extreme heat and cold weather events under the new or modified
Reliability Standard. We believe that it is necessary to establish a set of common contingencies for all responsible
entities to analyze. Required contingencies, such as those listed in Table 1 of Reliability Standard TPL-001-5.1 (i.e.,
category P1 through P7), establish common planning events that set the starting point for transmission system planning
assessments.”).
Id. at P 113 (“[T]he contingencies required in the new or revised Reliability Standards should reflect the
complexities of transmission system planning studies for extreme heat and cold weather events.”)
72

39

In defining the Contingencies to be considered for the Extreme Temperature Assessment,
the drafting team considered that the Commission referred to the Contingencies used in Table 1 of
Reliability Standard TPL-001-5.1 (category P0 through P7). The drafting team also considered the
Commission’s statement that it is “necessary to establish a set of common contingencies for all
responsible entities to analyze.” 73 Requiring the study of predefined Contingencies, such as those
listed in Table 1 of the proposed standard, would ensure a level of uniformity across planning
regions, considering that extreme heat and cold weather events often exceed the geographic
boundaries of most existing planning footprints.
The drafting team determined to define the Contingencies in Table 1 of proposed
Reliability Standard TPL-008-1 consistently with Table 1 of Reliability Standard TPL-001-5.1 to
advance the goal of commonality. If feasible, all Contingencies listed in Table 1 should be
considered for evaluation by the responsible entity; however, the language of proposed
Requirement R7 affords flexibility to responsible entities in identifying the most appropriate
Contingencies. The responsible entity should implement a method and establish sufficient
supporting rationale to ensure Contingencies within each category of Table 1 that are expected to
produce more severe System impacts within its planning area are adequately identified.
In developing proposed Reliability Standard TPL-008-1 Table 1, the drafting team
included the categories P0 (No Contingency), P1 (Single Contingency), and P7 (Multiple
Contingency, Common Structure) Contingencies from Reliability Standard TPL-001-5.1 Table 1,
as the drafting team determined these events represent the more likely Contingencies to occur. The
drafting team included the P7 Contingency category because common structure Contingencies are
often evaluated after categories P0 and P1 as the most common minimum level of transmission

73

Id. at P 112.

40

reliability assessment. In considering these events to have a higher likelihood of occurrence, the
drafting team considered the following:
•

Historical events that include simultaneous forced outages due to tripping of the
double-circuit power lines due to electrical storms events;

•

Environment-caused factors include pollution buildup, such as dust, that could cause a
faulted condition that trips both transmission lines on a common tower;

•

Avian-caused outages could impact both transmission lines on a common tower;

•

Smoke from nearby wildfires could cause simultaneous tripping of both circuits on a
common tower;

•

Nearby wildfires could impact system operation, as system operators proactively deenergize both lines on a common tower to avoid further impact to the transmission grid
in the event of a simultaneous tripping of both lines that may be carrying high power
transfer between areas;

•

Weather-related causes, such as lightning, flooding, wind, or icing, could cause tripping
of both transmission lines on a common tower;

•

A natural disaster, such as a winter storm, could cause a transmission tower to collapse,
taking out both lines strung on the same tower;

•

Other incidents, such as vehicle accidents, aircraft accidents, vandalism, or animal
contact, could adversely impact both transmission lines on the common tower.

Additionally, loss of two circuits running in parallel simultaneously is likely to have a
greater system impact versus loss of two unrelated or geographically separated circuits. Therefore,
there is greater potential for reliability concerns, especially during heavy transfers that are likely
during periods of extreme weather, due to loss of both circuits of a double-circuit line.
In developing the rationale for selected Contingencies, responsible entities should consider
past studies, subject matter expert knowledge of the responsible entity’s System (to be
supplemented with data or analysis), historical data from past operating events, or other relevant
considerations.
Since the benchmark planning cases are developed from the benchmark temperature
events, they already represent extreme System conditions. Thus, not all Contingencies from
Reliability Standard TPL-001-5.1 Table 1 are included in the TPL-008-1 Table 1 for assessment.
41

The drafting team determined to exclude the categories P2, P3, P4, P5, P6 Contingencies in
Reliability Standard TPL-001-5.1 Table 1 in the proposed TPL-008-1 Table 1 for the reasons listed
below.
The drafting team determined to exclude the category P2 (Single Contingency) and P4
(Multiple Contingency Fault plus stuck breaker) Contingencies due to the lower probability of
occurrence than the P1 and P7 contingencies. Proposed Reliability Standard TPL-008-1 focuses
on the single Contingencies (P1) or multiple Contingencies on common structure (P7) that are
more likely to be monitored in operational scenarios. Category P2 Contingencies (e.g.
Contingencies caused by internal breaker fault, bus section fault, opening line section without a
fault), and category P4 Contingencies (e.g. Contingencies caused by stuck breaker), while
plausible under extreme temperature conditions, occur with much less frequency than category P1
and P7 Contingencies.
The drafting team determined to exclude the category P3 (Multiple Contingency) and
category P6 (Multiple Contingency Two Overlapping singles) Contingencies due to the
complexity of those Contingencies, which involve multiple element outages triggered by multiple
Contingencies, with System adjustments allowed between them. The drafting team determined
that the likelihood of the P3 and P6 Contingencies occurring could be even lower compared to the
category P1 and P7 Contingencies. Moreover, the drafting team determined that excluding the
category P3 and P6 Contingencies would be justified, as generation and transmission derates or
outages are already accounted for within the benchmark planning cases. In Order No. 896, the
Commission emphasized the importance of incorporating derated generation, transmission
capacity, and the availability of generation and transmission in the development of benchmark
planning cases, which is reflected in proposed Requirements R3 and R4. As responsible entities

42

must consider potential concurrent or correlated generation and transmission outages or derates
within relevant benchmark planning cases, the benchmark planning case accurately reflects
System conditions under extreme temperatures, with generation and transmission derates or
outages already factored into the analysis.
The drafting team also determined to exclude the category P5 Contingency (Multiple
Contingency - fault plus non-redundant component of a Protection System failure to operate) in
proposed Reliability Standard TPL-008-1 Table 1. The drafting team determined to exclude the
category P5 Contingency because studying this contingency would impose a significant burden
while not providing commensurate benefits to reliability. Studying category P5 Contingency
events often requires a significant level of engineering analysis (including protection or control
analysis). These analyses are sensitive to the System topology and expected dispatch. As the
benchmark temperature event planning cases that are developed for proposed Reliability Standard
TPL-008-1 represent System conditions that are different than the typical summer or winter peak
conditions, the drafting team determined that the development of category P5 Contingency events
would be a significant burden. Further, evaluating this contingency would be unlikely to result in
further insight beyond the general reliability improvements associated with eliminating and
addressing the single point of failure included in the event definition.
In developing the BES voltage levels for the Contingencies in proposed Reliability
Standard TPL-008-1 Table 1, the drafting team reviewed previous major wide-area events and
found that the facilities that were out of service by these events have voltages that are 200 kV and
above. Therefore, the drafting team established voltages of 200 kV and above for Contingencies
in Table 1. The monitoring of potential impact is still applicable to Facilities with all BES voltage
levels. However, the drafting team recognized that many Planning Coordinators and Transmission

43

Planners have Contingencies that include all BES levels. Responsible entities may elect to use the
existing Contingencies that they already have and report the criteria violations for the categories
in Table 1.
K.

Requirement R8

Proposed Reliability Standard TPL-008-1 Requirement R8 establishes requirements for
Extreme Temperature Assessment studies. Proposed Requirement R8 would provide as follows:
R8.

Each responsible entity, as identified in Requirement R1, shall complete steady
state and transient stability analyses in the Extreme Temperature Assessment using
the Contingencies identified in Requirement R7, and shall document the
assumptions and results. Steady state and transient stability analyses shall be
performed for the following:
8.1.

Benchmark planning cases developed in accordance with Requirement R4
Part 4.1.

8.2.

Sensitivity cases developed in accordance with Requirement R4 Part 4.2.

Proposed Requirement R8 includes requirements for steady state and transient stability
analyses, using the Contingencies identified in Requirement R7 (referencing Table 1), for the
benchmark planning cases and sensitivity cases developed under Requirement R4. Proposed
Requirement R8 addresses the Commission’s directive in paragraph 111 of Order No. 896, in
which the Commission directed NERC to require responsible entities to perform both steady state
and transient stability (dynamic) analyses in extreme heat and extreme cold weather planning
studies. As the Commission explained:
In a steady state analysis, the system components are modeled as either in-service
or out-of-service and the result is a single point-in-time snapshot of the system in a
state of operating equilibrium. A transient stability (dynamic) analysis examines
the system from the start to the end of a disturbance to determine if the system
regains a state of operating equilibrium. Performing both analyses ensures that the
system has been thoroughly assessed for instability, uncontrolled separation, and
cascading failures in both the steady state and the transient stability realms. 74

74

Order No. 896 at P 111.

44

Proposed Requirement R8 addresses this directive by requiring both analyses for the benchmark
planning cases and sensitivity cases, for a total of four required studies. Entities shall document
the assumptions and results of these studies.
Along with proposed Requirement R3 discussed above, proposed Requirement R8 also
addresses the Commission’s Order No. 896 paragraph 124 directives relating to sensitivity cases.
Specifically, proposed Requirement R8 would “require the use of sensitivity cases to demonstrate
the impact of changes to the assumptions used in the benchmark planning case,” and that sensitivity
cases “should consider including conditions that vary with temperature such as load, generation,
and system transfers.” Since the benchmark planning case(s) already include System conditions
under extreme heat or extreme cold events, the sensitivity analysis shall include changes to at least
one of the following conditions: generation, real and reactive forecasted Load, or transfers. Under
the proposed standard, Planning Coordinators or Transmission Planners would have the flexibility
to include further sensitivity assessments to change more conditions should they wish to do so.
L.

Requirement R9

Proposed Reliability Standard TPL-008-1 Requirement R9 establishes requirements for
Corrective Action Plans when studies indicate the system will not perform in accordance with the
standard. NERC defines a Corrective Action Plan as “a list of actions and associated timetable for
implementation to remedy as specific problem.” Proposed Requirement R9 would provide as
follows:
R9.

Each responsible entity, as identified in Requirement R1, shall develop a Corrective
Action Plan(s) when the analysis of a benchmark planning case, in accordance with
Requirement R8 Part 8.1, indicates its portion of the Bulk Electric System is unable
to meet performance requirements for category P0 or P1 in Table 1. For each
Corrective Action Plan, the responsible entity shall:
9.1.

Document alternative(s) considered when Non-Consequential Load Loss is
utilized as an element of a Corrective Action Plan for a Table 1 P1
Contingency.
45

9.2.

Be permitted to utilize Non-Consequential Load Loss as an interim solution,
which normally is not permitted for category P0 in Table 1, in situations
that are beyond the control of the Planning Coordinator or Transmission
Planner that prevent the implementation of a Corrective Action Plan in the
required timeframe, provided that the responsible entity documents the
situation causing the problem, alternatives evaluated, and takes actions to
resolve the situation.

9.3.

Make its Corrective Action Plan available to, and solicit feedback from,
applicable regulatory authorities or governing bodies responsible for retail
electric service issues.

9.4.

Be allowed to have revisions to the Corrective Action Plan in subsequent
Extreme Temperature Assessments, provided that the planned Bulk Electric
System shall continue to meet the performance requirements of Table 1.

Consistent with paragraphs 152 and 157 of Order No. 896, proposed Requirement R9
would require entities to develop a Corrective Action Plan for specified instances when
performance standards are not met. 75 Under proposed Reliability Standard TPL-008-1, responsible
entities would be required to develop Corrective Action Plans to address performance deficiencies
for categories P0 and P1 in benchmark planning cases analyzed in the Extreme Temperature
Assessment. The drafting team determined to require Corrective Action Plans for these
deficiencies due to the higher likelihood of these events occurring. Furthermore, having a
Corrective Action Plan requirement for categories P0 and P1 in benchmark planning cases helps
to ensure resilience during future extreme cold and extreme heat temperature events. Proposed
Requirement R10, discussed in the following section, addresses the actions responsible entities
must take when potential system performance issues are identified for the remaining studies.

Order No. 896 at P 152 (“[W]e direct NERC to require in the new or modified Reliability Standard the
development of extreme weather corrective action plans for specified instances when performance standards are not
met.”) See also Order No. 896 at P 157 (“[W]e direct NERC to require in the new or modified Reliability Standard
the development of corrective action plans that include mitigation for specified instances where performance
requirements for extreme heat and cold events are not met—i.e., when certain studies conducted under the Standard
show that an extreme heat or cold event would result in cascading outages, uncontrolled separation, or instability”)
and P 158 (“[W]e give NERC in this final rule the flexibility to specify the circumstances that require the
development of a corrective action plan.”).

75

46

Proposed Requirement R9 addresses the issue of using Non-Consequential Load Loss as
an element of a Corrective Action Plan to address identified deficiencies. 76 In some instances, load
shed may be necessary to prevent system-wide failures and ensure the continued operation of
essential services during extreme heat and cold temperature events. Given that the category P0
represents a continuous system condition without any system disturbances, the drafting team
determined that Non-Consequential Load Loss should not be allowed as an element of Corrective
Action Plan to address a performance deficiency identified through studies of the benchmark
planning case. However, the drafting team has determined that Non-Consequential Load Loss may
be considered as an element of a Corrective Action Plan to address a deficiency identified through
studies of the category P1 Contingency.
Proposed Requirement R9 contains four sub-parts for required Corrective Action Plans.
Under Requirement R9 Part 9.1, responsible entities would be required to document alternative(s)
considered when Non-Consequential Load Loss is utilized as an element of a Corrective Action
Plan for a Table 1 P1 Contingency. Under Requirement R9 Part 9.2, responsible entities would be
able to use Non-Consequential Load Loss as an interim solution, which normally is not permitted
for category P0 in Table 1, in situations that are beyond the control of the Planning Coordinator or
Transmission Planner that prevent the implementation of a Corrective Action Plan in the required
timeframe, provided that the responsible entity documents the situation causing the problem,
alternatives evaluated, and takes actions to resolve the situation. This provision recognizes that

The NERC Glossary defines Non-Consequential Load Loss as “Non-Interruptible Load loss that does not
include: (1) Consequential Load Loss, (2) the response of voltage sensitive Load, or (3) Load that is disconnected
from the System by end- user equipment.” (The term Consequential Load Loss, used in this definition, is defined as
“All Load that is no longer served by the Transmission system as a result of Transmission Facilities being removed
from service by a Protection System operation designed to isolate the fault.”)

76

47

certain circumstances may make Non-Consequential Load Loss unavoidable, at least on a
temporary basis, and is similar to Reliability Standard TPL-001-5.1 Requirement R7 Part 2.7.3.
To provide visibility to the local authorities of matters relating to Corrective Action Plan
implementation, proposed Requirement R9 Part 9.3 would require responsible entities to share
their Corrective Action Plans with, and solicit feedback from, the applicable regulatory authorities
or governing bodies responsible for retail electric service. This provision is responsive to the
Commission’s directive in paragraph 165 of Order No. 896, in which the Commission directed
NERC to require that “responsible entities share their corrective action plans with, and solicit
feedback from, applicable regulatory authorities or governing bodies responsible for retail electric
service issues.” 77 This provision, along with Requirements R9 Part 9.1 and 9.2 addressing the
permitted uses of Non-Consequential Load Loss and alternative actions considered, would address
the Commission’s directive in paragraph 167 that responsible entities identify and share with these
authorities alternatives to load shedding that would, if approved and implemented, avoid the use
of load shedding. 78 Such alternatives could include, for example, building additional generation or
transmission capacity, energy efficiency programs, and demand load response programs.
Proposed Requirement R9 Part 9.4 provides that the responsible entity may revise its
Corrective Action Plan in subsequent Extreme Temperature Assessments, provided that the
planned Bulk Electric System shall continue to meet the performance requirements of Table 1.
This provision is consistent with similar language for Corrective Action Plans included in
Reliability Standard TPL-001-5.1 (Requirement R7 Part 2.7). This provision would allow

Order No. 896 at P 165.
Order No. 896 at P 167 (“Further, because an important goal of transmission planning is to avoid load shed,
any responsible entity that includes non-consequential load loss in its corrective action plan should also identify and
share with applicable regulatory authorities or governing bodies responsible for retail electric service alternative
corrective actions that would, if approved and implemented, avoid the use of load shedding.”).

77
78

48

responsible entities to incorporate approved mitigation measures from other planning assessments,
such as an annual transmission reliability assessment performed under Reliability Standard TPL001-5 or other planning assessments for policy-driven or economic needs.
M.

Requirement R10

Proposed Reliability Standard TPL-008-1 Requirement R10 establishes requirements for
entities to act when studies performed under the Extreme Temperature Assessment indicate that
the occurrence of less likely Contingencies during a benchmark temperature event could have
severe impacts on reliability. Proposed Requirement R10 would provide as follows:
R10.

Each responsible entity, as identified in Requirement R1, shall evaluate and
document possible actions designed to reduce the likelihood or mitigate the
consequences and adverse impacts of the event(s) if analyses conclude there could
be instability, uncontrolled separation, or Cascading within an Interconnection, for
the following:
10.1.

Table 1 P7 Contingencies in benchmark planning cases analyzed in
accordance with Requirement R8 Part 8.1.

10.2.

Categories P0, P1, and P7 in Table 1 in sensitivity cases analyzed in
accordance with Requirement R8 Part 8.2.

Proposed Requirement R10 carries forward the risk-based framework of Reliability
Standard TPL-001-5.1, in which entities are required to develop Corrective Action Plans to address
system performance issues for the more likely planning scenarios, and to evaluate and to consider
potential actions to mitigate consequences for the less likely planning scenarios.
Under proposed Requirement R10 Part 10.1, responsible entities would be required to
evaluate and document possible actions designed to reduce the likelihood or mitigate the
consequences and adverse impacts when the study results in benchmark planning cases analyses
conclude there could be instability, uncontrolled separation, or Cascading for category P7
Contingencies. Category P7 Contingencies involve multiple element outages resulting from a
single event, making them relatively less likely to occur compared to categories P0 and P1;
49

however, they may cause more severe system impacts. Considering both the likelihood of these
Contingencies, and the fact that the Extreme Temperature Assessment already addresses low
probability system conditions, the drafting team determined that Corrective Action Plans should
not be required for P7 Contingencies. However, due to the potential severity resulting from singleContingency multiple element outages, the drafting team determined it would be appropriate for
responsible entities to evaluate and document possible mitigation actions to reduce the likelihood
or mitigate the consequences and adverse impacts of the event(s) when analyses conclude there
could be instability, uncontrolled separation, or Cascading. The drafting team determined that
requiring the evaluation and documentation of the possible mitigating actions would allow a
responsible entity to see where major reliability concerns exist that may need to be addressed; if a
sufficiently large number of reliability concerns are identified, it may encourage the responsible
entity to consider and implement options for mitigating those concerns through transmission
upgrades.
Similarly, proposed Requirement R10 Part 10.2 would require the responsible entity to
document possible actions designed to reduce the likelihood or mitigate the consequences and
adverse impacts of the event(s) if analyses conclude there could be instability, uncontrolled
separation, or Cascading for the Categories P0, P1, and P7 sensitivity cases. In Order No. 896, the
Commission directed NERC to require “the use of sensitivity cases to demonstrate the impact of
changes to the assumptions used in the benchmark planning case.” 79 The Commission deferred to
NERC, however, to define the circumstances that would require the development of a Corrective
Action Plan. 80 The drafting team determined that Corrective Action Plans should not be required
Order No. 896 at P 124.
See Order No. 896 at P 158 (“[W]e give NERC in this final rule the flexibility to specify the circumstances
that require the development of a corrective action plan. For example, NERC should determine whether corrective

79
80

50

for sensitivity analysis for the following reasons. Sensitivity analysis is an important component
of a robust transmission planning study. A requirement to develop and implement Corrective
Action Plans for sensitivity cases may incentivize responsible entities to select fewer or less severe
sensitivities. An incentive to select fewer sensitivities is undesirable, because sensitivity study
results are used to identify constraints and initiate deeper analysis into the variables that impact
those constraints. The study results of sensitivity cases are also important to inform the
development of Corrective Action Plans in the benchmark planning cases. For these reasons, the
drafting team determined that the proposed standard should require the responsible entity to
evaluate and document possible actions designed to reduce the likelihood or mitigate the
consequences and adverse impacts of the event(s) when analyses of sensitivity cases conclude
there could be instability, uncontrolled separation, or Cascading for the categories P0, P1, and P7
analyses, but not require the entity to develop a Corrective Action Plan.
N.

Requirement R11

Proposed Reliability Standard TPL-008-1 Requirement R11 establishes requirements for
the sharing of Extreme Temperature Assessment results. Proposed Requirement R11 would
provide as follows:
R11.

Each responsible entity, as identified in Requirement R1, shall provide its Extreme
Temperature Assessment results within 60 calendar days of a request to any
functional entity that has a reliability related need and submits a written request for
the information.

Proposed Requirement R11 is responsive to that part of the Commission’s directive in
paragraph 72 of Order No. 896 directing NERC to require responsible entities to share the results

action plans should be required for single or multiple sensitivity cases, and whether corrective action plans should be
developed if a contingency event that is not already included in benchmark planning case would result in cascading
outages, uncontrolled separation, or instability.”).

51

of Extreme Temperature Assessment studies with affected Transmission Operators, Transmission
Owners, Generator Owners, and other functional entities with a reliability need for the studies. 81
Under proposed Requirement R11, a responsible entity must share Extreme Temperature
Assessment results with any functional entity that has a reliability related need and submits a
written request for the information within 60 calendar days of the request. This requirement, which
is modeled on information sharing requirements in Reliability Standards TPL-001-5.1 and TPL007-4 with modifications appropriate to the Extreme Temperature Assessment process,
emphasizes coordination and sharing of study findings. It would help ensure collaboration among
stakeholders and timely dissemination of critical information to entities with reliability-related
needs, thereby fostering a collective understanding of reliability concerns identified in wide-area
studies and enhancing overall grid reliability.
O.

Consideration of Order No. 896 Directives Regarding Probabilistic Analysis
and the MOD-032 Standard

In developing proposed Reliability Standard TPL-008-1, the drafting team considered
additional directives from Order No. 896 not specifically addressed in the discussion above. These
directives addressed: (1) consideration of probabilistic elements in the development of proposed
Reliability Standard; and (2) consideration of whether the MOD-032 Reliability Standard should
be revised to facilitate the exchange of information needed to complete Extreme Temperature
Assessments. The drafting team’s consideration of these directives is summarized below.
1. Paragraphs 134, 138 Directives for Consideration of Including
Probabilistic Elements in Extreme Temperature Planning Studies
In paragraph 134 of Order No. 896, the Commission directed NERC “to determine during
the standard development process whether probabilistic elements can be incorporated into the new

81

Order No. 896 at P 72.

52

or modified Reliability Standard and implemented presently by responsible entities,” 82 and if such
elements could be included, NERC should include them. Conversely, if NERC determined that
probabilistic methods would improve upon existing practices but were deemed infeasible to
include, NERC should explain in its petition “the barriers preventing the implementation” of those
methods. 83
In considering the use of probabilistic elements in accordance with paragraph 134, the
drafting team determined that, while incorporating probabilistic analysis would be a good step
forward, specific mandatory Reliability Standard requirements for probabilistic analysis would be
better suited for the future as the methods, processes, tools, and data sets mature. The drafting team
discussed requiring probabilistic assessment of generation and transmission facilities for the
benchmark planning cases in developing proposed Reliability Standard TPL-008-1. As a practical
matter, entities could incorporate probabilistic elements into their approach for meeting
requirements in proposed Reliability Standard TPL-008-1. For example, when a benchmark
temperature event is selected, the Planning Coordinator could include the use of probabilistic
approaches for some elements of their process for developing the benchmark planning cases under
proposed Requirement R3. Probabilistic tools are used for developing temperature dependent load
forecasts and determining how the temperature would impact different types of generation (e.g.,
de-rates and outages). The tools make use of historical weather data and other sources for region
and resource specific output. For example, gas plants may experience outages or de-rates due to
pipeline disruptions, fuel prioritization, or freezing of mechanical components. The probability of
any of those events occurring (and the relative impact) would be different depending on the region,

82
83

Order No. 896 at P 134.
Order No. 896 at P 138.

53

as well as the region in which the gas production is occurring. In complying with the proposed
standard, entities are likely to use probabilistic tools in this way, but as discussed below, it is not
required nor necessary to meet the reliability objectives of the proposed standard.
While probabilistic models and tools are capable and being used widely to perform
resource adequacy studies, where generation capability can be factored in regionally and
aggregated by fuel type, they are not in a mature state for transmission planning studies where
models represent specific generation and transmission facilities. More mature methods, processes,
and tools are needed for this granular modeling. The drafting team noted the limited data for
specific generator and transmission facility outages from extreme weather events. In reviewing
historical extreme heat and extreme cold temperature events, 84 the drafting team determined that
outages for generation and transmission facilities were unique for each of these events. The
impacts of extreme temperatures varied depending upon the nature of the event and the
characteristics of the affected regions. Thus, the drafting team found it challenging to draw
correlations for the outages that occurred for different extreme heat and cold events for different
regions and different timeframes. In addition, the drafting team determined that the data available
from these events was too limited to perform an adequate probabilistic assessment of generation
and transmission facilities. Thus, the drafting team concluded that the available information did
not support the development of specific probabilistic elements for inclusion in proposed Reliability

The drafting team reviewed reports analyzing the Winter Storm Uri and Winter Storm Elliot events, among
others. For more information on the Winter Storm Uri and Winter Storm Elliott events, see FERC-NERC Regional
Entity Staff Report: The February 2021 Cold Weather Outages in Texas and the South Central United States (Nov.
2021), available at https://www.ferc.gov/media/february-2021-cold-weather-outages-texas-and-south-central-unitedstates-ferc-nerc-and, and FERC, NERC, and Regional Entity Staff Report, Inquiry into Bulk-Power System
Operations During December 2022 Winter Storm Elliott (Oct. 2023), available at
https://www.ferc.gov/media/winter-storm-elliott-report-inquiry-bulk-power-system-operations-during-december2022.
84

54

Standard TPL-008-1, and that specific requirements for probabilistic elements would not be
effective at the current state of the art in transmission planning approaches.
For reasons explained in previous sections of this petition, proposed Reliability Standard
TPL-008-1 represents a just, reasonable, and technically sound means of achieving the
Commission’s reliability objectives in Order No. 896. NERC, however, anticipates that there may
be opportunities to improve the standard in the future, when additional data, as well as more mature
methods, processes, and tools, could allow for the development of meaningful probabilistic
elements for generation and transmission outages under extreme temperature conditions in
transmission planning assessments. Any such effort must balance the benefits and drawbacks of
probabilistic and deterministic approaches. While probabilistic approaches offer a more nuanced
view of risk, their inherent complexity, potential for underestimating critical events, and alignment
challenges with deterministic standards can pose significant drawbacks from a reliability
perspective. Discussions of probabilistic planning often reference the probability of a particular
BES element (e.g. generator, line, or transformer) experiencing an outage. Deterministic planning
assumes the probability is equal. Probabilistic assessments are based on a wide range of uncertain
variables (e.g., load forecasts, generation profiles, weather conditions, or equipment failures), and
the approaches may underemphasize rare, catastrophic events such as widespread blackouts
because such events have a low probability and may not significantly impact the overall risk
metrics. Deterministic approaches, by contrast, would allow planning entities to be certain that the
system is planned to a set of standardized criteria. Further development and maturation of
probabilistic planning methods would allow NERC to consider how to best incorporate these
methods to advance reliability in transmission planning studies in the future, such as through the
development of hybrid approaches.

55

NERC notes that both NERC and the Commission have taken steps in recent years to
improve transmission system planning, including the development and use of probabilistic
elements in transmission planning studies. As noted in Order No. 896, the Commission convened
a staff-led technical conference in June 2021 that focused on improving planning practices,
including exploring best practices for developing probabilistic methods for estimating planning
inputs. 85 NERC has explored through its reliability assessment work the development and
incorporation of probabilistic approaches. NERC recently partnered with the National Academy
of Engineering to provide recommendations on the evolution of resource and transmission
adequacy planning criteria based on probabilistic methods. A joint report, published in July 2024,
highlights the need for coordinated probabilistic generation and transmission studies to assess
resource and transmission adequacy and makes recommendations to gain acceptance across the
industry. 86
As described in the draft ERO Enterprise Process for TPL-008-1 Benchmark Weather
Event Development and Maintenance document, 87 NERC anticipates an ongoing review of
relevant considerations and feedback when updating the ERO benchmark event library for
subsequent Extreme Temperature Assessments. While NERC has not determined the precise
forum for this review at this time, NERC notes that it has many tools available for seeking
feedback, including public comment periods, the work of its technical committees, and technical
conferences. To the extent that this review indicates there are opportunities to enhance the existing
See Climate Change, Extreme Weather, and Electric System Reliability, Supplemental Notice of Technical
Conference, Docket No. AD21-13-000, at 4 (May 27, 2021).
86
NERC and the National Academy of Engineering, Section 6, Evolving Planning Criteria for a Sustainable
Power
Grid:
A
Workshop
Report,
July
2024,
available
at
https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/Evolving_Planning_Criteria_for_a_Sustaina
ble_Power_Grid.pdf.
87
See draft ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and
Maintenance document, Exhibit G (Summary of Development History and Complete Record of Development) at
item 82.
85

56

benchmark temperature event criteria or otherwise improve TPL-008 planning studies, NERC
would consider these enhancements through its stakeholder processes and seek any necessary
Commission approvals at the appropriate time.
2. Paragraph 73, Regarding Modifications to the MOD-032 Standard
In paragraph 73 of Order No. 896, the Commission noted that NERC may need to revise
Reliability Standard MOD-032-1 Data for Power System Modeling and Analysis to ensure the
entities responsible for developing benchmark planning cases and conducting wide-area extreme
temperature studies will be able to request and receive the necessary data. 88 The drafting team
determined that the entities responsible for completing the Extreme Temperature Assessment
under proposed Reliability Standard TPL-008-1 would be able to obtain data through the MOD032 standard, and that no revisions were needed at this time.
In considering this directive, the drafting team determined that Reliability Standard MOD032-1 ensures an adequate means of data collection for transmission planning and requires
applicable registered entities to provide steady-state, dynamic, and short circuit modeling data to
their Transmission Planners and Planning Coordinators. As provided in Reliability Standard
MOD-032-1 Requirement R1 and Attachment 1, the standard provides for the collection of various
data, such as in-service status and capability associated with demand, generation, and transmission
associated with various case types, scenarios, system operating states, or conditions for the longterm planning horizon. Reliability Standard MOD-032-1 also requires applicable registered
entities to provide “other information requested by the Planning Coordinator or Transmission
Planner necessary for modeling purposes.” Because Planning Coordinators and Transmission
Planners would be the entities responsible for performing tasks needed to complete the Extreme

88

Order No. 896 at P 73.

57

Temperature Assessment, these entities would be able to request and receive the necessary data
under Reliability Standard MOD-032-1. Therefore, the drafting team concluded that there was no
need to revise Reliability Standard MOD-032-1 at this time.
VI.

ENFORCEABILITY OF PROPOSED RELIABILITY STANDARDS
Proposed Reliability Standard TPL-008-1 includes measures that support each requirement

by clearly identifying what is required and how the ERO will enforce the requirement. These
measures help ensure that the requirements will be enforced in a clear, consistent, and nonpreferential manner and without prejudice to any party. 89 Additionally, proposed Reliability
Standard TPL-008-1 includes VRFs and VSLs. The VRFs and VSLs provide guidance on the way
that NERC will enforce the requirements of the proposed Reliability Standard. The VRFs and
VSLs for the proposed Reliability Standard comport with NERC and Commission guidelines
related to their assignment. Exhibit G provides a detailed review of the VRFs and VSLs, and the
analysis of how the VRFs and VSLs were determined using these guidelines.
VII.

EFFECTIVE DATE OF THE PROPOSED RELIABILITY STANDARDS
NERC respectfully requests that the Commission approve proposed Reliability Standard

TPL-008-1 to become effective as set forth in the proposed implementation plan, provided in
Exhibit B hereto. Proposed Reliability Standard TPL-008-1 would require the performance of an
Extreme Temperature Assessment at least once every five calendar years (Requirement R1). The
proposed implementation plan would provide a staggered approach over five years for the
performance of the first Extreme Temperature Assessment. Consistent with Order No. 896, the
phased-in compliance dates would begin 12 months from the effective date of regulatory approval
of proposed Reliability Standard TPL-007-1.

89

Order No. 672 at P 327.

58

The proposed implementation plan provides that proposed Reliability Standard TPL-0081 and the definition of Extreme Temperature Assessment would become effective on the first day
of the first calendar quarter that is 12 months after the effective date of the Commission’s order
approving the proposed Reliability Standard. Entities would be required to comply with
Requirement R1 pertaining to the identification of individual and joint responsibilities for
completing the Extreme Temperature Assessment, by this date. Entities would have an additional
24 months past the effective date to comply with Requirements R2, R3, R4, R5, and R6, and an
additional 48 months past the effective date to comply with Requirements R7, R8, R9, R10, and
R11.
In developing the proposed implementation timeframe, the drafting team considered the
Commission’s directive in paragraph 188 of Order No. 896, in which the Commission directed
NERC to propose an implementation timeline for its proposed Reliability Standard with
implementation beginning no later than 12 months after the effective date of a Commission order
approving the standard. 90 Under the proposed implementation plan, responsible entities would
need to comply with Requirement R1 within 12 months. In establishing the remaining compliance
dates, the drafting team considered the scope of coordination that will be required to perform
Extreme Temperature Assessments under the proposed standard, including completing each of the
discrete tasks identified in Requirements R2 through R11 for the first time. The drafting team
determined that five years represented a reasonable period to complete this work; further, the five
year implementation timeframe reflects the five-year periodicity for Extreme Temperature
Assessments in proposed Reliability Standard TPL-008-1. The proposed implementation plan
balances the urgency in the need to implement the proposed Reliability Standard against the

90

Order No. 896 at P 188.

59

reasonableness of the time allowed for those who must comply to develop the necessary processes
and capabilities to perform these new wide-area extreme temperature studies. The proposed
implementation plan for proposed Reliability Standard TPL-008-1 is therefore just and reasonable,
consistent with Commission guidance in Order No. 672, and responsive to the Commission’s
guidance for the implementation of this standard in Order No. 896. NERC respectfully requests
approval of the proposed implementation plan as submitted by NERC.

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

proposed Reliability Standard TPL-008-1, including the definition of Extreme
Temperature Assessment, and the associated elements included in Exhibit A,
effective as proposed herein; and

•

the proposed Implementation Plan included in Exhibit B.

Respectfully submitted,
/s/ Lauren A. Perotti
Lauren A. Perotti
Assistant General Counsel
North American Electric Reliability Corporation
1401 H Street NW, Suite 410
Washington, D.C. 20005
202-400-3000
[email protected]
Counsel for the North American Electric Reliability Corporation
Date: December 17, 2024

60

Exhibit A
Proposed Reliability Standard TPL-008-1

RELIABILITY | RESILIENCE | SECURITY

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

This is the final draft of the proposed standard.
Completed Actions

Date

Standards Committee approved Standard Authorization Request (SAR)
for posting

July 19, 2023

SAR posted for comment

August 8–September 27,
2023

45-day formal comment period with initial ballot

March 20–May 3, 2024

38-day formal comment period with additional ballot

July 16–August 22, 2024

15-day formal comment period with additional ballot

October 7–21, 2024

15-day formal comment period with additional ballot

November 7–21, 2024

Anticipated Actions

Date

5-day final ballot

December 2–6, 2024

Board adoption

December 10, 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

New or Modified Term(s) Used in NERC Reliability Standards

This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):

Extreme Temperature Assessment – Documented evaluation of future Bulk Electric System
performance for extreme heat and extreme cold benchmark temperature events.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements for Extreme
Temperature Events

2.

Number:

TPL-008-1

3.

Purpose:

Establish Transmission system planning performance requirements to
develop a Bulk Power System (BPS) that will operate reliably during
extreme heat and extreme cold temperature events.

4.

Applicability:
4.1. Functional Entities:
4.1.1. Transmission Planner
4.1.2. Planning Coordinator

5.

Effective Date: See Implementation Plan for Project 2023-07.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

B. Requirements and Measures
R1. Each Planning Coordinator shall identify, in conjunction with its Transmission
Planner(s), each entity’s individual and joint responsibilities for completing the
Extreme Temperature Assessment, which shall include each of the responsibilities
described in Requirements R2 through R11. Each responsible entity shall complete its
responsibilities such that the Extreme Temperature Assessment is completed at least
once every five calendar years. [Violation Risk Factor: Lower] [Time Horizon: Long-term
Planning]
M1. Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
provide dated documentation of each entity’s individual and joint responsibilities,
such as meeting minutes, agreements, copies of procedures, or protocols in effect
between entities or between departments of a vertically integrated system, or email
correspondence that identifies an agreement has been reached on individual and joint
responsibilities for completing the Extreme Temperature Assessment, and that these
responsibilities were completed such that the Extreme Temperature Assessment was
completed once every five calendar years.
R2. Each Planning Coordinator shall identify the zone(s) to which the Planning Coordinator
belongs to under Attachment 1 and shall coordinate with all Planning Coordinators
within each of its identified zone(s), to identify one common extreme heat benchmark
temperature event and one common extreme cold benchmark temperature event for
each of its identified zone(s) when completing the Extreme Temperature Assessment.
The benchmark temperature events shall be obtained from the benchmark library
maintained by the ERO or developed by the Planning Coordinators. Each benchmark
temperature event identified by the Planning Coordinators shall: [Violation Risk
Factor: High] [Time Horizon: Long-term Planning]
2.1. Consider no less than a 40-year period of temperature data ending no more than
five years prior to the time the benchmark temperature events are selected; and
2.2. Represent one of the 20 most extreme temperature conditions based on the
three-day rolling average of daily maximum (heat) or daily minimum (cold)
temperature across the zone.
M2. Each Planning Coordinator shall have evidence in either electronic or hard copy format
that it identified the zone(s) to which it belongs to, under Attachment 1, and that it
coordinated with all other Planning Coordinators within each of its identified zone(s)
to identify one common extreme heat benchmark temperature event and one
common extreme cold benchmark temperature event meeting the criteria of
Requirement R2 for each of their identified zone(s) when completing the Extreme
Temperature Assessment.
R3. Each Planning Coordinator shall coordinate with all Planning Coordinators within each
of its zone(s) identified in Requirement R2, to implement a process for developing
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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

benchmark planning cases for the Extreme Temperature Assessment that represent
the benchmark temperature events selected in Requirement R2 and sensitivity cases
to demonstrate the impact of changes to the basic assumptions used in the
benchmark planning cases. This process shall include the following: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
3.1. Selection of System models within the Long-Term Transmission Planning Horizon
to form the basis for the benchmark planning cases.
3.2. Forecasted seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers within the zone.
3.3. Assumed seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers in areas outside the zone, as needed.
3.4. Identification of changes to at least one of the following conditions for sensitivity
cases: generation, real and reactive forecasted Load, or transfers.
M3. Each Planning Coordinator shall have dated evidence that it implemented a process
for coordinating the development of benchmark planning cases and sensitivity cases
for the Extreme Temperature Assessment as specified in Requirement R3.
R4. Each responsible entity, as identified in Requirement R1, shall use the process
developed in Requirement R3 and data consistent with that provided in accordance
with the MOD-032 standard, supplemented by other sources as needed, to develop
the following and establish category P0 as the normal System condition in Table 1:
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. One common extreme heat and one common extreme cold benchmark planning
case.
4.2. One common extreme heat and one common extreme cold sensitivity case.
M4. Each responsible entity, as identified in Requirement R1, shall have dated evidence in
either electronic or hard copy format that it developed benchmark planning cases and
sensitivity cases in accordance with Requirement R4.
R5. Each responsible entity, as identified in Requirement R1, shall have criteria for
acceptable System steady state voltage limits and post-Contingency voltage deviations
for completing the Extreme Temperature Assessment. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning]
M5. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of the documentation, specifying the criteria for
acceptable System steady state voltage limits and post-Contingency voltage deviations
for completing the Extreme Temperature Assessment.
R6. Each responsible entity, as identified in Requirement R1, shall define and document
the criteria or methodology to be used in the Extreme Temperature Assessment to
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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

identify instability, uncontrolled separation, or Cascading within an Interconnection.
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
M6. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, specifying the criteria or
methodology to be used in the Extreme Temperature Assessment to identify
instability, uncontrolled separation, or Cascading within an Interconnection in
accordance with Requirement R6.
R7. Each responsible entity, as identified in Requirement R1, shall identify the
Contingencies for each category in Table 1 that are expected to produce more severe
System impacts on its portion of the Bulk Electric System. The rationale for those
Contingencies selected for evaluation shall be available as supporting information.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M7. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of the Contingencies for each
category in Table 1 that are expected to produce more severe System impacts on its
portion of the Bulk Electric System along with supporting rationale.
R8. Each responsible entity, as identified in Requirement R1, shall complete steady state
and transient stability analyses in the Extreme Temperature Assessment using the
Contingencies identified in Requirement R7, and shall document the assumptions and
results. Steady state and transient stability analyses shall be performed for the
following: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
8.1. Benchmark planning cases developed in accordance with Requirement R4 Part
4.1.
8.2. Sensitivity cases developed in accordance with Requirement R4 Part 4.2.
M8. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of the assumptions and results of
the steady state and transient stability analyses completed in the Extreme
Temperature Assessment.
R9. Each responsible entity, as identified in Requirement R1, shall develop a Corrective
Action Plan(s) when the analysis of a benchmark planning case, in accordance with
Requirement R8 Part 8.1, indicates its portion of the Bulk Electric System is unable to
meet performance requirements for category P0 or P1 in Table 1. For each Corrective
Action Plan, the responsible entity shall: [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
9.1. Document alternative(s) considered when Non-Consequential Load Loss is
utilized as an element of a Corrective Action Plan for a Table 1 P1 Contingency.
9.2. Be permitted to utilize Non-Consequential Load Loss as an interim solution,
which normally is not permitted for category P0 in Table 1 for situations that are
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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

beyond the control of the Planning Coordinator or Transmission Planner that
prevent the implementation of a Corrective Action Plan in the required
timeframe, provided that the responsible entity documents the situation causing
the problem, alternatives evaluated, and takes actions to resolve the situation.
9.3. Make its Corrective Action Plan available to, and solicit feedback from, applicable
regulatory authorities or governing bodies responsible for retail electric service
issues.
9.4. Be permitted to have revisions to the Corrective Action Plan in subsequent
Extreme Temperature Assessments, provided that the planned Bulk Electric
System shall continue to meet the performance requirements of Table 1.
M9. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of each Corrective Action Plan
developed in accordance with Requirement R9 when the analysis of a benchmark
planning case indicates its portion of the Bulk Electric System is unable to meet
performance requirements for category P0 or P1 in Table 1. Evidence shall include
documentation of correspondence with applicable regulatory authorities or governing
bodies responsible for retail electric service issues and any revision history.
R10. Each responsible entity, as identified in Requirement R1, shall evaluate and document
possible actions designed to reduce the likelihood or mitigate the consequences and
adverse impacts of the event(s) if analyses conclude there could be instability,
uncontrolled separation, or Cascading within an Interconnection, for the following:
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
10.1. Table 1 P7 Contingencies in benchmark planning cases analyzed in accordance
with Requirement R8 Part 8.1.
10.2. Categories P0, P1, and P7 in Table 1 in sensitivity cases analyzed in accordance
with Requirement R8 Part 8.2.
M10. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation that it evaluated and documented
possible actions designed to reduce the likelihood or mitigate the consequences and
adverse impacts when the analyses conclude there could be instability, uncontrolled
separation, or Cascading within an Interconnection for Table 1 P7 Contingencies in
benchmark planning cases or categories P0, P1, or P7 in Table 1 in sensitivity cases.
R11. Each responsible entity, as identified in Requirement R1, shall provide its Extreme
Temperature Assessment results within 60 calendar days of a request to any
functional entity that has a reliability related need and submits a written request for
the information. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M11. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as email notices, documentation of updated web pages, or postal receipts
showing recipient, that it provided its Extreme Temperature Assessment to any

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

functional entity who has a reliability need within 60 calendar days of a written
request.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

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 period(s) 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 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 responsible entity shall retain evidence of compliance with each
requirement in this standard for five calendar years or one complete
Extreme Temperature Assessment cycle, whichever is longer.

1.3. Compliance Monitoring and Enforcement Program: “Compliance Monitoring
Enforcement Program” or “CMEP” means, depending on the context (1) the
NERC Compliance Monitoring and Enforcement Program (Appendix 4C to the
NERC Rules of Procedure) or the Commission-approved program of a Regional
Entity, as applicable, or (2) the program, department or organization within
NERC or a Regional Entity that is responsible for performing compliance
monitoring and enforcement activities with respect to Registered Entities’
compliance with Reliability Standards.

Final Draft of TPL-008-1
December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events
Steady State & Stability:
a. Instability, uncontrolled separation, or Cascading within an Interconnection, defined in accordance with Requirement R6,
shall not occur.
b. Consequential Load Loss as well as generation loss is acceptable as a consequence of any event excluding P0.
c. Simulate the removal of all elements that Protection Systems and other controls are expected to automatically disconnect
for each event.
d. Simulate Normal Clearing unless otherwise specified.
e. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such
adjustments are executable within the time duration applicable to the Facility Ratings.
Steady State Only:
f. Applicable Facility Ratings shall not be exceeded.
g. System steady state voltages and post-Contingency voltage deviations shall meet the criteria identified in Requirement R5.

Final Draft of TPL-008-1
December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events

Category

P0
No
Contingency
P1
Single
Contingency

Initial
Condition

Normal
System

Normal
System

P7
Multiple
Contingency
(Common
Structure)

Normal
System

Final Draft of TPL-008-1
December 2024

Event1

Fault
Type3

None

N/A

Loss of one of the following:
1. Generator
2. Transmission Circuit
3. Transformer2
4. Shunt Device4

3Ø

5. Single Pole of a DC line

SLG

The loss of:
1. Any two adjacent (vertically
or horizontally) circuits on
common structure5
2. Loss of a bipolar DC line

SLG

Interruption
of Firm
Contingency
Transmission
BES Level
Service
Allowed

Non-Consequential Load Loss
Allowed
Benchmark
Planning
Cases

Sensitivity
Cases

N/A

Yes

No6

Yes

≥ 200 kV

Yes

Yes6

Yes

≥ 200 kV

Yes

Yes

Yes

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events
1. If the event analyzed involves BES elements at multiple System voltage levels, the lowest System voltage level of the
element(s) removed for the analyzed event determines the BES level of the event. For P7 events, the BES level of the event is
the highest System voltage level of the element(s) removed for the analyzed event.
2. For non-generator step up transformer outage events, the reference voltage, as used in footnote 1, applies to the low-side
winding (excluding tertiary windings). For generator and Generator Step Up transformer outage events, the reference
voltage applies to the BES connected voltage (high-side of the Generator Step Up transformer). Requirements which are
applicable to transformers also apply to variable frequency transformers and phase shifting transformers.
3. Unless specified otherwise, simulate Normal Clearing of faults. Single line to ground (SLG) or three-phase (3Ø) are the fault
types that must be evaluated in Stability simulations for the event described. A 3Ø or a double line to ground fault study
indicating the criteria are being met is sufficient evidence that a SLG condition would also meet the criteria.
4. Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
5. Excludes circuits that share a common structure for 1 mile or less.
6. Benchmark planning cases require the development of a Corrective Action Plan when the responsible entity’s portion of the
BES is unable to meet the performance requirements for categories P0 or P1. Additionally, in benchmark planning cases,
Non-Consequential Load Loss is not permitted for category P0 except where permitted as an interim solution in a Corrective
Action Plan in accordance with Requirement R9 Part 9.2.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels
Violation Severity Levels

R#
R1.

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed less than
or equal to six months late.

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than six months but less than
or equal to 12 months late.

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than 12 months but less than
or equal to 18 months late.

The Planning Coordinator, in
conjunction with its
Transmission Planner(s), failed
to identify individual and joint
responsibilities for completing
the Extreme Temperature
Assessment.
OR
The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than 18 months late.

R2.

N/A

Final Draft of TPL-008-1
December 2024

N/A

The Planning Coordinator
coordinated with all Planning
Coordinators within each
identified zone to identify one
common extreme heat and
one common extreme cold
benchmark temperature event
for completing the Extreme
Temperature Assessment, but
one of the identified events

The Planning Coordinator
coordinated with all Planning
Coordinators within each
identified zone to identify one
common extreme heat and
one common extreme cold
benchmark temperature event
for completing the Extreme
Temperature Assessment, but
both of the identified events

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

failed to meet all the criteria of failed to meet all of the criteria
Requirement R2.
of Requirement R2.
OR
The Planning Coordinator
failed to coordinate with all
Planning Coordinators within
each identified zone to identify
one common extreme heat
and one common extreme
cold benchmark temperature
event for completing the
Extreme Temperature
Assessment.
R3.

N/A

N/A

N/A

The Planning Coordinator did
not coordinate with all
Planning Coordinators within
each of its identified zone(s) to
implement a process for
developing benchmark
planning cases.
OR
The Planning Coordinator
coordinated with all Planning
Coordinators within each of its
identified zone(s) to
implement a process for
developing benchmark
planning cases, but the
process did not include all of
the required elements.

Final Draft of TPL-008-1
December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R4.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
did not use the process
developed in Requirement R3
to develop benchmark
planning cases or sensitivity
cases.
OR
The responsible entity, as
identified in Requirement R1,
used the process developed in
Requirement R3 to develop
benchmark planning cases and
sensitivity cases, but did not
use data consistent with that
provided in accordance with
the MOD-032 standard,
supplemented by other
sources as needed, for one or
more of the required cases.
OR
The responsible entity, as
identified in Requirement R1,
used the process developed in
Requirement R3 and data
consistent with that provided
in accordance with the MOD032 standard, supplemented
as needed, but failed to
develop one or more of the
required planning or sensitivity
cases.

Final Draft of TPL-008-1
December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R5.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
did not have criteria for
acceptable System steady
state voltage limits and postContingency voltage
deviations for completing the
Extreme Temperature
Assessment.

R6.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
failed to define or document
the criteria or methodology to
be used in the Extreme
Temperature Assessment to
identify instability,
uncontrolled separation, or
Cascading within an
Interconnection.

R7.

N/A

N/A

The responsible entity, as
identified in Requirement R1,
identified Contingencies for
each category in Table 1 that
are expected to produce more
severe System impacts on its
portion of the Bulk Electric
System, but did not include
the rationale for those
Contingencies selected for
evaluation as supporting
information.

The responsible entity, as
identified in Requirement R1,
did not identify Contingencies
for each category in Table 1
that are expected to produce
more severe System impacts
on its portion of the Bulk
Electric System.

Final Draft of TPL-008-1
December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for
one or more sensitivity cases
in accordance with
Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for
one or more benchmark
planning cases in accordance
with Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document results for one or
more of the sensitivity cases in
accordance with Requirement
R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document results for one or
more of the benchmark
planning cases in accordance
with Requirement R8.
OR
The responsible entity, as
identified in Requirement R1,
failed to complete steady state
or transient stability analyses
and document results in the
Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, in
accordance with Requirement
R8.

R9.

N/A

Final Draft of TPL-008-1
December 2024

N/A

The responsible entity, as
identified in Requirement R1,
developed a Corrective Action
Plan in accordance with
Requirement R9, but failed to
make its Corrective Action
Plan available to, or solicit
feedback from, applicable

The responsible entity, as
identified in Requirement R1,
failed to develop a Corrective
Action Plan when the
benchmark planning case
study results indicate the
System is unable to meet
performance requirements for

Page 17 of 24

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

regulatory authorities or
governing bodies responsible
for retail electric service
issues.

R10.

N/A

N/A

The responsible entity, as
identified in Requirement R1,
evaluated and documented
possible actions to reduce the
likelihood or mitigate the
consequences and adverse
impacts of the event(s) when
analyses conclude there could
be instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Part 10.1,
but failed to evaluate and
document possible actions
where required under
Requirement R10 Part 10.2.

the Table 1 P0 or P1
Contingencies.
OR
The responsible entity, as
identified in Requirement R1,
developed a Corrective Action
Plan, but it was missing one or
more of the elements of
Requirement R9 Part 9.1, 9.3
and 9.4 (as applicable).
The responsible entity, as
identified in Requirement R1,
evaluated and documented
possible actions to reduce the
likelihood or mitigate the
consequences and adverse
impacts of the event(s) when
analyses conclude there could
be instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Part 10.2,
but failed to evaluate and
document possible actions
where required under
Requirement R10 Part 10.1.
OR
The responsible entity, as
identified in Requirement R1,
failed to evaluate and
document possible actions to

Final Draft of TPL-008-1
December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

reduce the likelihood or
mitigate the consequences
and adverse impacts of the
event(s) when analyses
conclude there could be
instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Parts 10.1
and 10.2.
R11.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 60 days but
less than or equal to 80 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 80 days but
less than or equal to 100 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 100 days but
less than or equal to 120 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 120 days
following the request.
OR
The responsible entity, as
identified in Requirement R1,
did not provide its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who submitted a written
request for the information.

D. Regional Variances
Final Draft of TPL-008-1
December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

None.

E. Associated Documents
•

Implementation Plan for Project 2023-07

•

Technical Rationale Document

•

Consideration of Issues and Directives for FERC Order 896.

•

ERO Benchmark Event Library

•

TPL-008 Data Library Read Me

Final Draft of TPL-008-1
December 2024

Page 20 of 24

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Version History
Version
1

Date
TBD

Final Draft of TPL-008-1
December 2024

Action

Change
Tracking

Addressing FERC Order 896

New Standard

Page 21 of 24

TPL-008-1 Supplemental Material

Attachment 1: Extreme Temperature Assessment Zones

The table below lists the zones to be used in the Extreme Temperature Assessment and
identifies the Planning Coordinators that belong to each zone. In accordance with Requirement
R2, each Planning Coordinator is required to identify the zone(s) to which it belongs. Planning
Coordinators, in different zones within a broader planning region, may use the same
benchmark temperature events for their respective benchmark planning cases, provided the
benchmark temperature events meet the criteria of Requirement R2 for each zone.
Zone
MISO North

MISO South
SPP North
SPP South
PJM
New England
New York
SERC
Florida
Central Canada
Ontario
Maritimes

Southwest
Pacific Northwest

Final Draft of TPL-008-1
December 2024

Planning Coordinators

Eastern Interconnection
Planning Coordinator(s) in MISO that serve
portions of MISO in Montana, North Dakota,
South Dakota, Minnesota, Iowa, Wisconsin,
Michigan, Indiana, Illinois, Missouri, and
Kentucky
Planning Coordinator(s) in MISO that serve
portions of Arkansas, Mississippi, Louisiana, and
Texas
Planning Coordinator(s) in portions of SPP that
serve Iowa, Montana, Nebraska, North Dakota,
and South Dakota.
Planning Coordinator(s) in portions of SPP that
serve Arkansas, Kansas, Louisiana, Missouri, New
Mexico, Oklahoma, and Texas.
Planning Coordinator(s) that serves PJM
Planning Coordinator(s) in NPCC that serve the six
New England States
Planning Coordinator(s) in NPCC that serve New
York
Planning Coordinator(s) in SERC, excluding those
that serve Florida and those in MISO, SPP, and
PJM
Planning Coordinator(s) in SERC that serve Florida
Planning Coordinator(s) that serve Saskatchewan
and Manitoba region of MRO
Planning Coordinator(s) in NPCC that serve
Ontario
Planning Coordinator(s) in NPCC that primarily
serve New Brunswick, Nova Scotia, Prince Edward
Island, and Northern Maine
Western Interconnection
Planning Coordinator(s) in the Southwest region
of WECC, including El Paso in West Texas
Planning Coordinator(s) in the Pacific Northwest
region of WECC

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TPL-008-1 Supplemental Material

Great Basin
Rocky Mountain
California/Mexico
Western Canada
ERCOT
Quebec

Final Draft of TPL-008-1
December 2024

Zone

Planning Coordinators
Planning Coordinator(s) in the Great Basin region
of WECC
Planning Coordinator(s) in the Rocky Mountain
region of WECC
Planning Coordinator(s) in the California/Mexico
region of WECC
Planning Coordinator(s) that primarily serve
British Columbia and Alberta region of WECC
ERCOT Interconnection
Planning Coordinator(s) in Texas that are part of
the ERCOT Interconnection
Quebec Interconnection
Planning Coordinator(s) that serve Quebec in the
NPCC Region.

Page 23 of 24

TPL-008-1 Supplemental Material

The map below depicts an approximation of the zones to be used in the Extreme Temperature
Assessment and is provided as a visual aid; to the extent that there is a conflict between the
map and the table, the table controls. This map is not to be used for compliance purposes.
TPL-008-1 Weather Zones Map

Final Draft of TPL-008-1
December 2024

Page 24 of 24

Exhibit B
Implementation Plan

RELIABILITY | RESILIENCE | SECURITY

Implementation Plan

Project 2023-07 Transmission System Planning Performance
Requirements for Extreme Weather
Reliability Standard TPL-008-1
Applicable Standard
•

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature
Events

Requested Retirement
•

Not applicable

Prerequisite Standard
•

Not applicable

Applicable Entities
•

Planning Coordinators

•

Transmission Planners

New Term in the NERC Glossary of Terms

This section includes all newly defined, revised, or retired terms used or eliminated in the NERC Reliability
Standard. New or revised definitions listed below become approved when the proposed standard is
approved. When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
•

Extreme Temperature Assessment – Documented evaluation of future Bulk Electric System
performance for extreme heat and extreme cold benchmark temperature events.

Background

On June 15, 2023, the U.S. Federal Energy Regulatory Commission (“FERC”) issued Order No. 896, a final
rule directing NERC to develop a new or modified Reliability Standard to address the lack of a long-term
planning requirement(s) for extreme heat and cold weather events.1 Specifically, FERC directed NERC to
develop modifications to Reliability Standard TPL-001-5.1 or develop a new Reliability Standard that
requires the following: (1) development of benchmark planning cases based on major prior extreme heat
and cold weather events and/or meteorological projections; (2) planning for extreme heat and cold weather
1

Transmission System Planning Requirements for Extreme Weather, Order No. 896, 183 FERC ¶ 61,191 (2023).

RELIABILITY | RESILIENCE | SECURITY

events using steady state and transient stability analyses expanded to cover a range of extreme weather
scenarios including the expected resource mix’s availability during extreme heat and cold weather
conditions, and including the wide-area impacts of extreme heat and cold weather; and (3) development
of Corrective Action Plans that mitigate any instances where performance requirements for extreme heat
and cold weather events are not met. FERC further directed NERC to ensure that the proposed new or
modified Reliability Standard becomes mandatory and enforceable beginning no later than 12 months from
the effective date of FERC approval.

General Considerations

Proposed Reliability Standard TPL-008-1 would require the performance of an Extreme Temperature
Assessment at least once every five calendar years (Requirement R1). This implementation plan provides a
staggered approach for the performance of the first Extreme Temperature Assessment, with phased-in
compliance dates beginning 12 months from the effective date of regulatory approval consistent with Order
No. 896. For subsequent Extreme Temperature Assessments, entities may establish timeframes appropriate
to their facts and circumstances for carrying out their responsibilities under the standard, provided that the
Extreme Temperature Assessment is completed no later than five calendar years following the previous
Extreme Temperature Assessment.

Effective Date

The effective date for the proposed Reliability Standard is provided below. Where the standard drafting
team identified the need for a longer implementation period for compliance with a particular section of the
proposed Reliability Standard (e.g., an entire Requirement or a portion thereof), the additional time for
compliance with that section is specified below. These phased-in compliance dates represent the dates that
entities must begin to comply with that particular section of the Reliability Standard, even where the
Reliability Standard goes into effect at an earlier date.
TPL-008-1 and Definition

Where approval by an applicable governmental authority is required, the standard and definition of
Extreme Temperature Assessment shall become effective on the first day of the first calendar quarter that
is twelve (12) 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 twelve (12) months after the date the standard
and definition of Extreme Temperature Assessment is adopted by the NERC Board of Trustees, or as
otherwise provided for in that jurisdiction.

Phased-In Compliance Dates

Compliance Date for TPL-008-1 Requirement R1

Entities shall be required to comply with Requirement R1, pertaining to the identification of individual and
joint responsibilities for completing the Extreme Temperature Assessment, upon the effective date of
Reliability Standard TPL-008-1.

Implementation Plan
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | December 2024

2

Compliance Date for TPL-008-1 Requirements R2, R3, R4, R5, R6

Entities shall not be required to comply with Requirements R2, R3, R4, R5, and R6 until twenty-four (24)
months after the effective date of Reliability Standard TPL-008-1.
Compliance Date for TPL-008-1 Requirements R7, R8, R9, R10, R11

Entities shall not be required to comply with Requirements R7, R8, R9, R10, and R11 until forty-eight (48)
months after the effective date of Reliability Standard TPL-008-1.
Figure 1: Implementation Plan, Demonstrating Effective Date
and Phased-in Compliance Dates from the effective date of
the governmental authority’s order approving this standard

Initial Performance of Periodic Requirements

Entities shall complete the Extreme Temperature Assessment no later than forty-eight (48) months after
the effective date of Reliability Standard TPL-008-1. Subsequent Extreme Temperature Assessments shall
be completed by no later than five calendar years following the completion of the previous Extreme
Temperature Assessment.

Implementation Plan
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | December 2024

3

Exhibit C
Order No. 672 Criteria

RELIABILITY | RESILIENCE | SECURITY

EXHIBIT C
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 proposed Reliability Standard TPL-008-1 has 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
Proposed Reliability Standard TPL-008-1 – Transmission System Planning Performance

Requirements for Extreme Temperature Events is a new Reliability Standard, developed in
response to Order No. 896, 3 focused specifically on improving how Planning Coordinators and
Transmission Planners plan for the potential impacts of extreme heat and extreme cold temperature
events on the reliable operation of the Bulk-Power System. The proposed Reliability Standard

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.”).
3
Order No. 896, Transmission System Planning Performance Requirements for Extreme Weather, 183 FERC
¶ 61,191 (2023) [hereinafter Order No. 896].
1

consists of a framework, consisting of 11 requirements, for the performance of periodic studies
assessing the wide-area impacts of extreme heat and extreme cold temperature events on the BulkPower System. These periodic studies are referred to as Extreme Temperature Assessments.
Proposed Reliability Standard TPL-008-1 would require planning entities in a planning zone,
defined in Attachment 1 to the standard, to coordinate with each other on the development of
Extreme Temperature Assessments. The proposed standard contains requirements addressing
coordination, requirements addressing the creation of benchmark temperature events (based on
analysis of historical weather data), requirements addressing the creation of planning cases based
on the benchmark temperature events, requirements for steady state and transient stability analyses
including sensitivity cases, requirements for entities to develop Corrective Action Plans in
specified instances where system performance requirements are not met, and requirements for the
sharing of study information and any Corrective Action Plans developed to address system
performance issues.
Proposed Reliability Standard TPL-008-1 is thus designed to achieve a specific reliability
goal and contains a technically sound means to achieve that goal.
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. 4
Proposed Reliability Standard TPL-008-1 is clear and unambiguous as to what is required

and who is required to comply, in accordance with Order No. 672. The proposed standard is
applicable to Planning Coordinators and Transmission Planners, the functional entities who

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

2

perform tasks related to planning the Bulk-Power System. As discussed further in the main
petition, the proposed standard clearly articulates the actions that applicable entities must take to
comply with the standard.
3.

A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation. 5
The Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) for proposed

Reliability Standard TPL-008-1 comport with NERC and Commission guidelines related to their
assignment, as discussed further in Exhibit F. 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 Standard includes clear and understandable
consequences in accordance with Order No. 672.
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. 6
Proposed Reliability Standard TPL-008-1 contains 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 would be enforced and help ensure that the
requirements would be enforced in a clear, consistent, and non-preferential manner and without
prejudice to any party.

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.”).
6
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.”).
5

3

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. 7
Proposed Reliability Standard TPL-008-1 achieves the reliability goal of improving how

entities plan for the wide area impacts of extreme heat and extreme cold temperature events on the
Bulk-Power System effectively and efficiently in accordance with Order No. 672. By design,
proposed Reliability Standard TPL-008-1 accounts for regional differences across North America:
the proposed benchmark temperature event criteria, developed following an analysis of historical
North American weather data, account for climate differences across regions, and the planning
zones reflect areas that have similar electric system properties and similar weather or
climatological patterns. While planning entities within a given zone retain flexibility to select the
appropriate benchmark events for study within the zone, the standard helps ensure that entities are
working together to select a sufficiently severe benchmark temperature event for study. In
determining the Contingencies that must be studied and the circumstances under which an entity
must develop a Corrective Action Plan to address system performance issues, the drafting team
carefully considered all relevant considerations, including the risks, benefits, and implementation
concerns associated with different approaches. The result is a proposed standard that achieves its
reliability goal effectively and efficiently.
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,

7
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.”).

4

but not at consequences of less than excellence in operating system reliability. 8
Proposed Reliability Standard TPL-008-1 does not reflect a “lowest common denominator”
approach. In accordance with the Commission’s direction in Order No. 896, the proposed standard
contains requirements that would advance the goal of improving how entities plan for the wide
area impacts of extreme heat and extreme cold temperature events while balancing the need for
manageable coordination among the entities responsible for carrying out the required studies. The
proposed requirements are intended to focus studies (and any necessary corrective actions
identified through these studies) on the scenarios most likely to occur during an extreme
temperature event.
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. 9
The proposed Reliability Standard would apply consistently throughout North America and

does not favor one geographic area or regional model. By design, the proposed standard considers
regional variations in climate and electric system properties.
8.

Proposed Reliability Standards should cause no undue negative effect on competition
or restriction of the grid beyond any restriction necessary for reliability. 10
Proposed Reliability Standard TPL-008-1 would have no undue negative effect on

competition and would not unreasonably restrict the available transmission capacity or limit the
use of the BPS in a preferential manner. The reliability need for improved transmission system
planning requirements for extreme temperature events is well documented, as highlighted in Order
No. 896.

5

9.

The implementation time for the proposed Reliability Standard is reasonable. 11
The implementation plan for proposed Reliability Standard TPL-008-1 is just and

reasonable and appropriately balances the urgency in the need to implement the standard against
the reasonableness of the time allowed for those who must comply to develop necessary
procedures or other relevant capability.
The proposed implementation plan, included as Exhibit B to this filing, provides that
proposed Reliability Standard TPL-008-1 and the definition of Extreme Temperature Assessment
would become effective on the first day of the first calendar quarter that is 12 months after the
effective date of the Commission’s order approving the proposed Reliability Standard. Entities
would be required to comply with Requirement R1 pertaining to the identification of individual

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
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.”).
9
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.”).
10
See Order No. 672, supra note 1, at P 332 (“As directed by section 215 of the FPA, the Commission 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.”).
11
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.”).
8

6

and joint responsibilities for completing the Extreme Temperature Assessment, by this date.
Entities would have an additional 24 months past the effective date to comply with Requirements
R2, R3, R4, R5, and R6, and an additional 48 months past the effective date to comply with
Requirements R7, R8, R9, R10, and R11.
In developing the proposed implementation timeframe, the drafting team considered the
Commission’s directive in paragraph 188 of Order No. 896, in which the Commission directed
NERC to propose an implementation timeline for its proposed Reliability Standard with
implementation beginning no later than 12 months after the effective date of a Commission order
approving the standard. 12 Under the proposed implementation plan, responsible entities would
need to comply with Requirement R1 within 12 months. In establishing the remaining compliance
dates, the drafting team considered the scope of coordination that will be required to perform
Extreme Temperature Assessments under the proposed standard, including completing each of the
discrete tasks identified in Requirements R2 through R11 for the first time. The drafting team
determined that five years represented a reasonable period to complete this new work; further, the
five year implementation timeframe reflects the five-year periodicity for Extreme Temperature
Assessments in proposed Reliability Standard TPL-008-1. The proposed implementation plan for
proposed Reliability Standard TPL-008-1 is therefore just and reasonable, consistent with
Commission guidance in Order No. 672, and responsive to the Commission’s guidance for the
implementation of this standard in Order No. 896.

12

Order No. 896 at P 188.

7

10.

The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process. 13
Proposed Reliability Standard TPL-008-1 was developed in accordance with NERC’s

Commission-approved processes for developing and approving Reliability Standards. Exhibit G
includes a summary of the development proceedings for the proposed standard, and details the
processes followed to develop the proposed standard. These processes included, among other
things, public comment and ballot periods. Additionally, all meetings of the 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. 14
NERC has identified no competing public interests regarding the proposed standard. No

comments were received that indicated that the proposed standard conflicts with other vital public
interests. Consistent with Order No. 896, the proposed standard would require each entity
developing a Corrective Action Plan to address system performance issues to share that plan with,
and solicit feedback from, the regulatory authority responsible for retail electric service issues in
the jurisdiction.

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.”).
14
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.”).
13

8

12.

Proposed Reliability Standards must consider any other appropriate factors. 15
No other negative factors relevant to whether the proposed Reliability Standard is just and

reasonable were identified.

15
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.”).

9

Exhibit D
Consideration of Order No. 896 Directives

RELIABILITY | RESILIENCE | SECURITY

Consideration of FERC Order 896 Directives

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
December 2024
On June 15, 2023, FERC issued a Final Rule, Order No. 896, directing NERC to develop a new or modified Reliability Standard to address a lack
of a long-term planning requirement(s) for extreme heat and cold weather events. Specifically, FERC directed NERC to develop modifications to
Reliability Standard TPL-001-5.1 or to develop a new Reliability Standard to require the following: (1) development of benchmark planning
cases based on major prior extreme heat and cold weather events and/or meteorological projections; (2) planning for extreme heat and cold
weather events using steady state and transient stability analyses expanded to cover a range of extreme weather scenarios including the
expected resource mix's availability during extreme heat and cold weather conditions, and including the wide-area impacts of extreme heat
and cold weather; and (3) development of corrective action plans that mitigate any instances where performance requirements for extreme
heat and cold weather events are not met. FERC directed NERC to submit a new or revised standard within 18 months, or by December 2024.
The below provides the directives from FERC Order 896 along with the drafting team’s consideration of the directives.

Directive Language

FERC Order 896 Directives

P35. “[W]e direct NERC to: (1) develop extreme heat and cold weather
benchmark events, and (2) require the development of benchmark
planning cases based on identified benchmark events.”
P36: “…As recommended by commenters, NERC should consider the
examples of approaches for defining benchmark events identified in the
NOPR (e.g., the use of projected frequency or probability distribution).
NERC may also consider other approaches that achieve the objectives
outlined in this final rule.”

Consideration of Directives

The ERO has worked with respective subject matter experts, including
climate experts, the six regions, etc., to explore extreme heat and extreme
cold benchmark temperature events. NERC, in consultation with climate
data subject matter expert consultants on the benchmark events, utilized
publicly available modeled data to address the requirements of TPL-008-1
that define extreme heat and extreme cold benchmark temperature
events.
Specifically, based on the available data, the drafting team determined that
extreme benchmark temperature events must: 1) consider no less than
forty years of historical temperature data, 2) include recent temperature

RELIABILITY | RESILIENCE | SECURITY

Directive Language

FERC Order 896 Directives

Consideration of Directives

data due to ongoing climate changes, and 3) represent one of the twenty
worst extreme temperature conditions over the forty year period, based on
a 3-day rolling average of daily maximum (heat) or minimum (cold)
temperatures.
The ERO will maintain a library of benchmark temperature events that
meet these requirements. Responsible entities will be able to review and
select benchmark temperature events from this library to assist with the
development of benchmark planning cases. However, responsible entities
may also identify benchmark temperature events via their own processes,
provided that the event meets the criteria of Requirement R2 and is agreed
upon by all PCs within the zone.
Should the extreme heat and cold weather benchmark events provided not
suffice for the entities zone, the Planning Coordinator (PC) in coordination
with all PCs within its zone, may develop a common extreme heat and
extreme cold weather benchmark event to use for the TPL-008-1 Standard.
The drafting team developed requirements within TPL-008-1 to require PCs
within zones to select one common extreme heat benchmark temperature
event and one common extreme cold benchmark temperature event
(Requirement R2). After selecting its benchmark events, the responsible
entity is required to implement a process for coordinating the development
of benchmark planning cases and sensitivity cases among the responsible
entities (Requirement R3) and to develop benchmark planning cases and
sensitivity cases (Requirement R4).

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Directive Language

FERC Order 896 Directives

P37. “Because the impact of most extreme heat and cold events spans
beyond the footprints of individual planning entities, it is important that all
responsible entities likely to be impacted by the same extreme weather
events use consistent benchmark events. Doing so is important to ensuring
that neighboring planning regions are assuming similar weather conditions
and are able to coordinate their assumptions accordingly. As a result,
defining the benchmark event in a manner that provides responsible
entities significant discretion to determine the applicable meteorological
conditions would not meet the objectives of this final rule.”
P38. “[I]n developing extreme heat and cold benchmark events, NERC shall
ensure that benchmark events reflect regional differences in climate and
weather patterns.”

Consideration of Directives

NERC, in consultation with climate data subject matter expert consultants
on benchmark events, developed subregions or “zones” of North America
that are likely to experience similar weather conditions. These zones also
consider practical concerns with coordination such as the boundaries of
Interconnections and Balancing Authority Areas.
The drafting team developed Requirement R2 such that PCs within the
same zone are required to select one common extreme heat benchmark
temperature event and one common extreme cold benchmark
temperature event. This process balances the opportunity to provide input
with the need for common events to be modeled over wide areas.
NERC, in consultation with climate data subject matter expert consultants
on benchmark events, has utilized publicly available modeled data in the
last forty-three years (1980-2022), as well as more than eighty years of
projected hourly meteorology data from PNNL to ensure regional
differences in climate and weather patterns are reflected in the zones
depicted in Attachment 1 of TPL-008-1.
A Map has been added to the TPL-008-1 Standard showing the zones split
throughout the US and Canada. These are to be considered wide area, and
regional differences went into consideration when developing the data
based on extreme historical events over the past 40 years.

P39. “We also direct NERC to include in the Reliability Standard the
framework and criteria that responsible entities shall use to develop from
the relevant benchmark event planning cases to represent potential
weather-related contingencies (e.g., concurrent/correlated generation and
transmission outages, derates) and expected future conditions of the
system such as changes in load, transfers, and generation resource mix,
and impacts on generators sensitive to extreme heat or cold, due to the
weather conditions indicated in the benchmark events. Developing such a

The directive is addressed in Requirements R3 and R4 of the proposed TPL008-1 standard.
Requirement R3 obligates the PC to implement a process to coordinate the
development of the benchmark planning cases and sensitivity cases. This
process shall include: 1) the selection of System models within the LongTerm Transmission Planning Horizon to serve as a starting point for the
benchmark planning cases, 2) forecasted seasonal and temperature

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Directive Language

FERC Order 896 Directives

framework would provide a common design basis for responsible entities
to follow when creating benchmark planning cases. This would not only
help establish a clear set of expectations for responsible entities to follow
when developing benchmark planning events, but also facilitate auditing
and enforcement of the Standard.”

P40. “We also direct NERC to ensure the reliability standard contains
appropriate mechanisms for ensuring the benchmark event reflects up-todate meteorological data.”

P50. “[W]e…direct NERC to require that transmission planning studies
under the new or revised Reliability Standard consider the wide-area
impacts of extreme heat and cold weather. We direct NERC to clearly
describe the process that an entity must use to define the wide-area
boundaries. While commenters provide various views in favor of both a
geographical approach and electrical approach to defining wide-area
boundaries, we do not adopt any one approach in this final rule…NERC
should consider the comments in this proceeding when developing a new
or modified reliability standard that considers the broad area impacts of
extreme heat and cold weather.”

Consideration of Directives

dependent adjustments for Load, generation, Transmission, and transfers
within the zone to represent the selected benchmark temperature events,
3) assumed seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers outside of the zone as needed, and
4) the identification of changes to at least one of generation, real and
reactive forecasted load, or transfers to serve as a sensitivity case.
Requirement R4 obligates the responsible entity to develop benchmark
planning cases and sensitivity cases for performing the Extreme
Temperature Assessment which reflects System conditions from the
selected benchmark events. Requirement R4 also references the NERC
MOD-032 Reliability Standard that provides PCs and Transmission Planners
a mechanism for obtaining the data needed to develop the benchmark
planning cases.
Requirement R2 Part 2.1 requires that the temperature data collected to
identify benchmark temperature events includes 40 years of data “ending
no more than 5 years prior to the time the benchmark temperature events
are selected”. This requirement ensures that the window of time
considered for benchmark temperature events reflects up-to-date data.
The up-to five-year gap was included due to potential lags in data sources.
To understand the complexities of defining wide-area boundaries, the
drafting team reviewed the extreme weather events mentioned within
FERC Order No. 896, as well as the comments received during the FERC
Order proceeding. In addition, NERC consulted with climate data subject
matter experts who evaluated publicly available modeled data in the last
forty-three years (1980-2022) and more than eighty years of projected
hourly meteorology data from PNNL.
The drafting team struck a balance between a geographical approach and
an electrical approach by dividing North America into zones that are likely
to experience similar weather conditions but also consider practical

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Directive Language

FERC Order 896 Directives

P58. “[W]e…direct NERC to develop benchmark events for extreme heat
and cold weather events through the Reliability Standards development
process. We agree … that the development of adequate benchmark events
is critical and should be committed to the subject matter experts on the
standards drafting team. ”
P59. Further, requiring NERC to develop the new or modified Reliability
Standard’s benchmark events is consistent with the approach the
Commission took in Order No. 779, when the Commission directed NERC to
develop benchmark events for geomagnetic disturbance analyses.1 For
the same reasons, we also conclude that NERC is best positioned to define
mechanisms to periodically update extreme heat and cold weather
benchmark events, as discussed above.

Consideration of Directives

concerns with coordination such as the boundaries of Interconnections and
Balancing Authority Areas. These zones are depicted in Attachment 1 of
TPL-008-1, and PCs will be required to coordinate with all PCs in the zone(s)
they belong to.
The drafting team considered various approaches to developing benchmark
temperature events. With assistance from NERC’s subject matter expert
consultants, the drafting team identified the key components of
temperature events that are necessary for the event to constitute an
adequate benchmark temperature event. These components were
included in Requirement R2.
Specifically, based on the available data, the drafting team determined that
extreme benchmark temperature events must: 1) consider no less than
forty years of historical temperature data, 2) include recent temperature
data due to ongoing climate changes, and 3) represent one of the twenty
worst extreme temperature conditions over the forty year period based on
a 3-day rolling average of daily maximum (heat) or minimum (cold)
temperatures.
The ERO will maintain a library of benchmark temperature events that
meet these requirements. Responsible entities will be able to review and
select benchmark temperature events from this library to assist with the
development of benchmark planning cases. However, responsible entities
may also identify benchmark temperature events via their own processes
provided that the event meets the criteria of Requirement R2 and is agreed
upon by all PCs within the zone.

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Directive Language

FERC Order 896 Directives

P60. “[W]e…direct NERC to designate the type(s) of entities responsible for
developing benchmark planning cases and conducting wide-area studies
under the new or modified Reliability Standard…benchmark planning cases
should be developed by registered entities such as large planning
coordinators, or groups of planning coordinators, with the capability of
planning on a regional scope.”
P61: “We believe the designated responsible entities should have certain
characteristics, including having a wide-area view of the Bulk-Power
System and the ability to conduct long-term planning studies across a wide
geographic area. The responsible entities should also have the planning
tools, expertise, processes, and procedures to develop benchmark planning
cases and analyze extreme weather events in the long-term planning
horizon.”
P62: “To comply with this directive, NERC may designate the tasks of
developing benchmark planning cases and conducting wide-area studies to
an existing functional entity or a group of functional entities (e.g., a group
of planning coordinators). NERC may also establish a new functional entity
registration to undertake these tasks. In the petition accompanying the
proposed Reliability Standard NERC should explain how the applicable
registered entity or entities meet the objectives outlined above.”

Consideration of Directives

In addition to describing the minimum requirements of a benchmark
temperature event, Requirement R2 obligates PCs within the same zone to
coordinate in selecting one common extreme heat benchmark
temperature event and one common extreme cold benchmark
temperature event for completing the Extreme Temperature Assessment.
This coordination is required to ensure the benchmark temperature event
is reflected over a wide-area.
The drafting team discussed that the Transmission Planner (TP) and/or
Planning Coordinator (PC) would be the responsible entities to address TPL008-1 Requirements. Requirement R1 obligates both the TP and PC to
identify their individual and joint responsibilities.
Requirement R3 obligates each PC to implement a process for coordinating
the development of benchmark planning cases and sensitivity cases, using
the selected benchmark temperature events identified in Requirement R2.
This process must be implemented in coordination with all PCs within the
same zone.
Requirement R4 obligates each responsible entity, as identified in
Requirement R1, to use the coordination process developed in accordance
with Requirement R3 and data consistent with that provided in accordance
with the MOD-032 standard, supplemented by other sources as needed, to
develop benchmark planning cases and sensitivity cases.
The identification of joint and individual responsibilities in Requirement R1
provides a measure of flexibility for PCs and TPs to agree on a distribution
of responsibilities. Thus, while PCs are responsible for implementing the
case development process in Requirement R3, TPs may be responsible for
providing data and completing the case development according to that
process.

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Directive Language

FERC Order 896 Directives

P72. “[W]e direct NERC to require functional entities to share with the
entities responsible for developing benchmark planning cases and
conducting wide-area studies the system information necessary to develop
benchmark planning cases and conduct wide-area studies. Further,
responsible entities must share the study results with affected transmission
operators, transmission owners, generator owners, and other functional
entities with a reliability need for the studies.”

Consideration of Directives

The development of benchmark planning cases and sensitivity cases will
require cooperation amongst many PCs and TPs. By requiring participation
from all entities within a zone, TPL-008-1 ensures that the group of
functional entities have a sufficient wide-area view of the Bulk Power
System and the planning tools, expertise, processes and procedures
necessary for developing benchmark planning cases and sensitivity cases.
The directive is addressed in proposed TPL-008-1 in Requirements R3, R4
and R11.
Requirement R3 obligates each PC to implement a process for coordinating
the development of benchmark planning cases, using the selected
benchmark temperature events identified in Requirement R2, among all
Planning Coordinators within a zone.
Requirement R4 obligates each responsible entity, as identified in
Requirement R1, to use the coordination process implemented in
accordance with Requirement R3 and data consistent with that provided in
accordance with the MOD-032 standard, supplemented by other sources as
needed, to develop benchmark planning cases and sensitivity cases.

P73. “Because in this final rule we direct NERC to determine the
responsible entities that will be developing benchmark planning cases and
conducting wide-area studies, it is possible that the selected responsible
entities under the new or modified Reliability Standard will not be able to
request and receive needed data pursuant to MOD-032-1, absent
modification to that Standard.”

Requirement R11 obligates each responsible entity, as identified in
Requirement R1, to provide its Extreme Temperature Assessment results
within 60 calendar days of a request to any functional entity that has a
reliability related need and submits a written request for the information.
The drafting team discussed and determined that data needed to address
the Extreme Temperature Assessment would still be appropriate to receive
through MOD-032. MOD-032 ensures an adequate means of data
collection for transmission planning and requires applicable registered
entities to provide steady-state, dynamic, and short circuit modeling data
to their Transmission Planner(s) and Planning Coordinator(s). As outlined in
Requirement R1 and Attachment 1 of MOD-032, MOD-032 allows various

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Directive Language

FERC Order 896 Directives

P76: “[W]e…direct NERC to address the requirement for wide-area
coordination through the standards development process, giving due
consideration to relevant factors identified by commenters in this
proceeding.”
P77. “[W]e direct NERC to require in the new or modified Reliability
Standard that responsible entities share the results of their wide-area
studies with other registered entities such as transmission operators,
transmission owners, and generator owners that have a reliability related
need for the studies.”
P88. “[W]e direct NERC to require under the new or revised Reliability
Standard the study of concurrent/correlated generator and transmission
outages due to extreme heat and cold events in benchmark events as
described in more detail below.”
P92. “These contingencies (i.e., correlated/concurrent, temperature
sensitive outages, and derates) shall be identified based on similar

Consideration of Directives

data collection such as in-service status and capability associated with
demand, generation, and transmission associated with various case types,
scenarios, system operating states, or conditions for the long-term
planning horizon. MOD-032 also requires applicable registered entities to
provide “other information requested by the Planning Coordinator or
Transmission Planner necessary for modeling purposes” for each of the
three types of data required. Because the drafting team determined the
responsible entities that will be developing benchmark planning cases are
limited to Planning Coordinators and Transmission Planners, they will be
able to request and receive needed data pursuant to MOD-032. Thus, the
drafting team believes that there is no need to update MOD-032.
The drafting team reviewed all the extreme weather events mentioned
within the FERC Order 896. For this project, the drafting team focused the
scope of Requirement R3 to require each PC to implement a process for
coordinating the development of benchmark planning cases and sensitivity
cases, using the selected benchmark temperature events identified in
Requirement R2, among all PCs within a zone.
This directive is addressed in proposed TPL-008-1 Requirement R11.
Requirement R11 obligates each responsible entity to provide the widearea study results within 60 calendar days of a request to any functional
entity that has a reliability related need and has submitted a written
request for the information.
This directive is addressed in proposed TPL-008-1 through Requirements R3
and R4. Per Requirement R3 Part 3.2, the benchmark planning case
development process must include forecasted seasonal and temperature
dependent adjustments for Load, generation, Transmission, and transfers
within the zone. Per Requirement R4, the data necessary to build the
benchmark planning cases must be provided via MOD-032, supplemented
by other sources as needed. Any concurrent/correlated generator and
transmission outages due to extreme heat and cold events in benchmark

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Directive Language

FERC Order 896 Directives

Consideration of Directives

contingencies that occurred in recent extreme weather events or expected
to occur in future forecasted events.”

temperature events should be reflected in the model data and thus
represented in the initial conditions of the benchmark planning cases.

P111. “[W]e direct NERC to require in the proposed new or modified
Reliability Standard that responsible entities perform both steady state and
transient stability (dynamic) analyses in the extreme heat and cold weather
planning studies. In a steady state analysis, the system components are
modeled as either in-service or out-of-service and the result is a single
point-in-time snapshot of the system in a state of operating equilibrium. A
transient stability (dynamic) analysis examines the system from the start to
the end of a disturbance to determine if the system regains a state of
operating equilibrium. Performing both analyses ensures that the system
has been thoroughly assessed for instability, uncontrolled separation, and
cascading failures in both the steady state and the transient stability
realms.” (internal citations omitted).
P112. “[W]e direct NERC to define a set of contingencies that responsible
entities will be required to consider when conducting wide-area studies of
extreme heat and cold weather events under the new or modified
Reliability Standard. We believe that it is necessary to establish a set of
common contingencies for all responsible entities to analyze. Required
contingencies, such as those listed in Table 1 of Reliability Standard TPL001-5.1 (i.e., category P1 through P7), establish common planning events
that set the starting point for transmission system planning assessments.
Requiring the study of predefined contingencies will ensure a level of
uniformity across planning regions—a feature that will be necessary in the
new or revised Reliability Standard considering that extreme heat and cold
weather events often exceed the geographic boundaries of most existing
planning footprints.”

This directive is addressed in proposed TPL-008-1 through Requirement R8
and Table 1.
Requirement R8 requires the responsible entity to complete both steady
state and transient stability analyses and document the assumptions and
results.
Table 1 obligates each responsible entity to perform both steady state and
transient stability analyses and compare the study results against steady
state and stability performance requirements.
This directive is addressed in proposed TPL-008-1 through Requirement R7
and Table 1.
Requirement R7 requires the responsible entity to identify Contingencies
for completing the Extreme Temperature Assessment. The rationale, for
those Contingencies selected for evaluation, shall be available as
supporting information.
The Contingencies for each category in Table 1 of TPL-008-1 correspond to
the well-established Contingencies defined in Reliability Standard TPL-0015.1. Utilizing these well-established Contingencies will ensure a level of
uniformity across planning regions.

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Directive Language

FERC Order 896 Directives

P113: “[T]he contingencies required in the new or revised Reliability
Standards should reflect the complexities of transmission system planning
studies for extreme heat and cold weather events.”
P116. “[W]e direct NERC to require in the new or modified Reliability
Standard that responsible entities model demand load response in their
extreme weather event planning area. As indicated by several
commenters, because demand load response is generally a mitigating
action that involves reducing distribution load during periods of stress to
stabilize the Bulk-Power System, its effect during an extreme weather
event should be modeled.”
P 117: “[I]n addressing this directive, we expect NERC to determine
whether responsible entities will need to take additional steps to ensure
that the impacts of demand load response are accurately modeled in
extreme weather studies, such as by analyzing demand load response as a
sensitivity, as is currently the case under Reliability Standard TPL-001-5.1.”
P124. “[W]e direct NERC to require the use of sensitivity cases to
demonstrate the impact of changes to the assumptions used in the
benchmark planning case. Sensitivity analyses help a transmission planner
to determine if the results of the base case are sensitive to changes in the
inputs. The use of sensitivity analyses is particularly necessary when
studying extreme heat and cold events because some of the assumptions
made when developing a base case may change if temperatures change –
for example, during extreme cold events, load may increase as
temperatures decrease, while a decrease in temperature may result in a
decrease in generation. We… direct NERC to define during the Reliability
Standard development process a baseline set of sensitivities for the new or
modified Reliability Standard. While we do not require the inclusion of any
specific sensitivity in this final rule, NERC should consider including
conditions that vary with temperature such as load, generation, and system
transfers.”

Consideration of Directives

TPL-008-1 Requirement R4 meets this directive by requiring each
responsible entity to develop benchmark planning cases using data
consistent with that provided in accordance with the MOD-032 standard,
supplemented by other sources as needed.
Specifically, Attachment 1 of MOD-032 requires information requested by
the Planning Coordinator or Transmission Planner necessary for modeling
purposes.

This directive is addressed in proposed TPL-008-1 in Requirement R3, which
requires all PCs within the same zone to coordinate to implement a process
for developing benchmark planning cases and sensitivity cases. Sensitivity
cases are used to demonstrate the impact of changes to the basic
assumptions used in the benchmark planning cases. Per Requirement R3
Part 3.4, PCs must include provisions in the case development process to
identify changes to generation, real and reactive forecasted Load, and/or
transfers to develop sensitivity cases.
The identification of changes for sensitivity cases within the coordinated
process of Requirement R3 addresses the directive that precludes
responsible entities from determining sensitivities alone. However, nothing
prevents responsible entities from conducting additional sensitivity studies
they find relevant to their planning areas.

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Directive Language

FERC Order 896 Directives

P125. “We do not agree ... that responsible entities alone should determine
the sensitivity cases that must be considered in the responsible entity’s
study. … We…believe that responsible entities should be free to study
additional sensitivities relevant to their planning areas…cooperation will be
necessary between responsible entities conducting extreme heat and
extreme cold weather studies and other registered entities within their
extreme weather study footprints to ensure the selection of appropriate
sensitivities.”
P134. “[W]e directs NERC to require in the new or modified Reliability
Standard the use of planning methods that ensure adequate consideration
of the broad characteristics of extreme heat and cold weather conditions.
We further direct NERC to determine during the standard development
process whether probabilistic elements can be incorporated into the new
or modified Reliability Standard and implemented presently by responsible
entities. If NERC identifies probabilistic elements which responsible entities
can feasibly implement and that would improve upon existing planning
practices, we expect the inclusion of those methods in the proposed
Reliability Standard.”
P138. “[W]e direct NERC to identify during the standard development
process any probabilistic planning methods that would improve upon
existing planning practices, but that NERC deems infeasible to include in
the proposed Reliability Standard at this time. If any such methods are
identified, NERC shall describe in its petition for approval of the proposed
Reliability Standard the barriers preventing the implementation of those
probabilistic elements. We intend to use this information to determine
whether and what next steps may be warranted to facilitate the use of
probabilistic methods in transmission system planning practices.”
P152. “[W]e direct NERC to require in the new or modified Reliability
Standard the development of extreme weather corrective action plans for

Consideration of Directives

The drafting team discussed probabilistic elements and determined while
probabilistic analysis would be a good step forward, it would be better
suited for the future as the methodology, process, and tools mature.
Probabilistic assessment of generation and transmission facilities for the
benchmark planning cases was discussed during the process of drafting the
TPL-008-1 standard. However, based on the actual extreme heat and
extreme cold events that have occurred, outages for generation and
transmission facilities were unique for each of these events. Thus, it was
challenging to draw correlation for the outages that occurred for different
extreme heat and cold events for different regions and different
timeframes. In addition, the data, available from these events, was limited
to perform an adequate probabilistic assessment. Due to these reasons,
the drafting team has decided not to pursue any probabilistic assessment
for the current TPL-008-1 standard. This, however, does not preclude
future development of probabilistic assessment when having additional
data, as well as mature methodology, process and tools that can provide
meaningful probabilistic assessment for generation and transmission
outages under extreme temperature conditions.
The directive is addressed in the proposed TPL-008-1 Requirement R9.

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Directive Language

FERC Order 896 Directives

specified instances when performance standards are not met. In addition,
as explained below, we direct NERC to develop certain processes to
facilitate interaction and coordination with applicable regulatory
authorities or governing bodies responsible for retail electric service as
appropriate in implementing a corrective action plan.”
P155: “[T]he Commission is not directing any specific result or content of
the corrective action plan.”
P157. “[W]e direct NERC to require in the new or modified Reliability
Standard the development of corrective action plans that include
mitigation for specified instances where performance requirements for
extreme heat and cold events are not met—i.e., when certain studies
conducted under the Standard show that an extreme heat or cold event
would result in cascading outages, uncontrolled separation, or instability.”
P158: “[W]e give NERC in this final rule the flexibility to specify the
circumstances that require the development of a corrective action plan.”
P165. “[w]e direct NERC to require in the new or modified Reliability
Standard that responsible entities share their corrective action plans with,
and solicit feedback from, applicable regulatory authorities or governing
bodies responsible for retail electric service issues.”
P167. “Further, because an important goal of transmission planning is to
avoid load shed, any responsible entity that includes non-consequential
load loss in its corrective action plan should also identify and share with
applicable regulatory authorities or governing bodies responsible for retail
electric service alternative corrective actions that would, if approved and
implemented, avoid the use of load shedding.”

Consideration of Directives

When the benchmark planning case study results indicate the System is
unable to meet performance requirements for P0 and P1 Contingencies,
Corrective Action Plans (CAPs) must be developed. Additionally, in
accordance with Requirement R9 Part 9.1, responsible entities shall make
their CAP available to, and solicit feedback from, applicable regulatory
authorities or governing bodies responsible for retail electric service issues.

The directive is addressed in the proposed TPL-008-1 Requirement R9.
When the benchmark planning case study results indicate the system is
unable to meet performance requirements for P0 and P1 Contingencies,
Corrective Action Plans must be developed.

The directive is addressed in the proposed TPL-008-1 Requirement R9.
Requirement R9.1 requires the responsible entities to make their CAP
available and solicit feedback from applicable regulatory authorities or
governing bodies responsible for retail electric service issues.
This directive is addressed in proposed TPL-008-1 Requirement R9.
As stipulated in Requirement R9 Part 9.2, when Non-Consequential Load
Loss is utilized as an element of a CAP for a Table 1 P1 Contingency, the
responsible entity must document the alternative(s) considered, and notify
the applicable regulatory authorities or governing bodies responsible for
retail electric service issues.

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Directive Language

FERC Order 896 Directives

P188. “[W]e direct NERC to submit a new or modified Reliability Standard
within 18 months of the date of publication of this final rule in the Federal
Register. Further, we direct NERC to propose an implementation timeline
for the new or modified Reliability Standard, with implementation
beginning no later than 12 months after the effective date of a Commission
order approving the proposed Reliability Standard.”

P193. “[W]e direct NERC to establish an implementation timeline for the
proposed Reliability Standard. In complying with this directive, NERC will
have discretion to develop a phased-in implementation timeline for the
different requirements of the proposed Reliability Standard (i.e.,
developing benchmark cases, conducting studies, developing corrective
action plans). However, this phased-in implementation must begin within
12 months of the effective date of a Commission order approving the
proposed Reliability Standard and must include a clear deadline for
implementation of all requirements.”

Consideration of Directives

The directive is addressed with the publication of TPL-008-1 and will be
filed with the regulatory government no later than December 23, 2024,
within 18 months of the date Order No. 896 was published in the Federal
Register.
The implementation plan addresses Requirement R1 becoming effective 12
months from the effective date of the Commission order approving the
TPL-008-1. In addition, phased-in approaches have been provided for other
Requirements needing additional time. See the TPL-008-1 Implementation
Plan.
The implementation plan addresses Requirement R1 becoming effective 12
months from the effective date of the Commission order approving the
TPL-008-1. In addition, phased-in approaches have been provided for other
Requirements needing additional time. See the TPL-008-1 Implementation
Plan.

Consideration of FERC Order 896 Directives
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Exhibit E
Technical Rationale

RELIABILITY | RESILIENCE | SECURITY

Technical Rationale and
Justification for TPL-008-1
Project 2023-07 Transmission Planning
Performance Requirements for Extreme
Weather
December 2024

RELIABILITY | RESILIENCE | SECURITY

NERC | Report Title | Report Date
I

Table of Contents
Preface ........................................................................................................................................................................... iii
Introduction ................................................................................................................................................................... iv
Defined Terms ................................................................................................................................................................. 5
TPL-008-1 Standard ......................................................................................................................................................... 6
Requirement R1 .............................................................................................................................................................. 7
Requirement R2 .............................................................................................................................................................. 8
Requirement R3 ............................................................................................................................................................ 10
Requirement R4 ............................................................................................................................................................ 11
Requirement R5 ............................................................................................................................................................ 12
Requirement R6 ............................................................................................................................................................ 13
Requirement R7 ............................................................................................................................................................ 14
Requirement R8 ............................................................................................................................................................ 19
Requirement R9 ............................................................................................................................................................ 20
Requirement R10 .......................................................................................................................................................... 21
Requirement R11 .......................................................................................................................................................... 22

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Preface
Electricity is a key component of the fabric of modern society and the Electric Reliability Organization (ERO) Enterprise
serves to strengthen that fabric. The vision for the ERO Enterprise, which is comprised of NERC and the six Regional
Entities, is a highly reliable, resilient, and secure North American bulk power system (BPS). Our mission is to assure
the effective and efficient reduction of risks to the reliability and security of the grid.
Reliability | Resilience | Security
Because nearly 400 million citizens in North America are counting on us
The North American BPS is made up of six Regional Entities as shown on the map and in the corresponding table
below. The multicolored area denotes overlap as some load-serving entities participate in one Regional Entity while
associated Transmission Owners/Operators participate in another.

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

Texas RE

Texas Reliability Entity

WECC

WECC

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Introduction
This document explains the technical rationale and justification for the proposed Reliability Standard TPL-008-1. It
provides stakeholders and the ERO Enterprise with an understanding of the technology and technical requirements
in the Reliability Standard. This Technical Rationale and Justification for TPL-008-1 is not a Reliability Standard and
should not be considered mandatory and enforceable.

Background

On June 15, 2023, FERC issued FERC Order No. 896 that acknowledges the “challenges associated with planning for
extreme heat and cold weather events, particularly those that occur during periods when the Bulk-Power System
must meet unexpectedly high demand. Extreme heat and cold weather events have occurred with greater frequency
in recent years and are projected to occur with even greater frequency in the future. These events have shown that
load shed during extreme temperatures result in unacceptable risk to life and have extreme economic impact. As
such, the impact of concurrent failures of Bulk-Power System (BPS) generation and transmission equipment and the
potential for cascading outages that may be caused by extreme heat and cold weather events should be studied and
corrective actions should be identified and implemented.” 1
Therefore, the Commission directed in FERC Order No. 896 to develop a new or modified Reliability Standard to
address a lack of long-term planning requirement(s) for extreme heat and cold weather events. Specifically, FERC
directed NERC to develop modifications to Reliability Standard TPL-001-5.1 or a new Reliability Standard, to require
the following: (1) development of benchmark planning cases based on major prior extreme heat and cold weather
events and/or meteorological projections; (2) planning for extreme heat and cold weather events using steady state
and transient stability analyses expanded to cover a range of extreme weather scenarios including the expected
resource mix's availability during extreme heat and cold weather conditions, and including the wide-area impacts of
extreme heat and cold weather; and (3) development of corrective action plans that mitigate any instances where
performance requirements for extreme heat and cold weather events are not met.

1

N. Am. Elec. Reliability Corp., 183 FERC ¶ 61,191 (2023) (FERC Order), Final Rule. eLibrary | File List (ferc.gov)
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Defined Terms
The Drafting Team (DT) defined one term to be added to the NERC Glossary of Terms to make the requirements easier
to read and understand.
Extreme Temperature Assessment
Documented evaluation of future Bulk Electric System performance for extreme heat and extreme cold
benchmark temperature events.
The definition of Extreme Temperature Assessment was developed by the DT to limit wordiness throughout the
requirements.

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TPL-008-1 Standard
The FERC Order No. 896 directed NERC to submit a new Reliability Standard or modifications to Reliability Standard
TPL-001-5.1 to address the concerns pertaining to transmission system planning for extreme heat and cold weather
events that impact the Reliable Operation of the Bulk-Power System.
The SDT determined that a new Reliability Standard was the cleanest way to address FERC’s directives versus
modifying Reliability Standard TPL-001-5.1. While the TPL-008-1 standard uses similar requirements, this allows
industry to have one standard that focuses on extreme heat and extreme cold benchmark temperature events.
The purpose of TPL-008-1 is to “Establish Transmission system planning performance requirements to develop a Bulk
Power System (BPS) that will operate reliably during extreme heat and extreme cold temperature events.” The
directives in FERC Order No. 896 pertain to the reliable operation of the BPS, and the requirements of TPL-008-1
support that by ensuring Planning Coordinators and Transmission Planners are planning their portions of the Bulk
Electric System (BES) to meet performance requirements in extreme heat and extreme cold benchmark temperature
events.

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Requirement R1
Requirement R1 requires each Planning Coordinator (PC) and the Transmission Planner(s) (TP) within the PC’s
footprint to identify each entity’s individual and joint responsibilities when completing the Extreme Temperature
Assessment at least once every five calendar years. Due to significant level of data collection and coordination
between the Planning Coordinator(s) and Transmission Planner(s) for the potential wide-area extreme heat and
extreme cold benchmark events, as well as the need to document the assumptions and study results, the drafting
team opined that completing the Extreme Temperature Assessment once every five calendar years is a reasonable
timeframe to allow responsible entities to coordinate, prepare, perform, and document the study results. To the
extent that responsible entities want to complete more than one set of the Extreme Temperature Assessment for an
extreme heat and extreme cold benchmark event, they can do so, but the minimum requirement is once every five
calendar years to complete one set of the Extreme Temperature Assessment.
The purpose of this requirement is to have the PC and its TP(s) identify their individual and joint responsibilities for
the following activities:
•

Identifying the PC’s zone(s) and coordinating with all PCs in each of its identified zone(s) to select one
common extreme heat benchmark temperature event and one common extreme cold benchmark
temperature event (Requirement R2),

•

Implementing a process for developing benchmark planning cases and sensitivity cases (Requirement R3),

•

Developing benchmark planning cases and sensitivity cases (Requirement R4),

•

Having acceptable criteria (Requirements R5 and R6),

•

Identifying Contingencies for evaluation (Requirement R7),

•

Performing steady state and transient stability analyses (Requirement R8),

•

Developing Corrective Action Plans when required (Requirement R9),

•

Evaluating and documenting possible actions for performance deficiencies that do not require Corrective
Action Plans (Requirement R10), and

•

Providing study results to any functional entity that has a reliability related need (Requirement R11).

The responsibilities described in Requirements R2 and R3 are explicitly assigned to the PC. The responsibilities
described in Requirements R4 through R11 may be completed by either the PC or one or more of its TPs. Requirement
R1 requires that an agreement is reached on the individual and joint responsibilities for completing the Extreme
Temperature Assessment between the PC and its TPs.

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Requirement R2
Requirement R2 requires each Planning Coordinator (PC) to identify the zone(s) it will participate in for the
components of the Extreme Temperature Assessment that require coordination. PCs in the same zone are required
to coordinate to:
•

Select one common extreme heat benchmark temperature event and one common extreme cold benchmark
temperature event (Requirement R2), and

•

Implement a process for developing benchmark planning cases and sensitivity cases (Requirement R3).

FERC Order No. 896 directed NERC to require that transmission planning studies under the new or revised Reliability
Standard consider the wide-area impacts of extreme heat and cold weather. Considering this directive, the SDT
identified the zones depicted in Attachment 1 as reasonable boundaries that balance the need for studies to cover
large regions with similar weather patterns with the need for a manageable level of coordination. An earlier proposal
to limit coordination to only adjacent PCs was not adequate for meeting FERC’s directives. While the zones depicted
in Attachment 1 will require some PCs to coordinate with many other PCs, the industry has demonstrated, through
various working groups and organizations, that it is capable of cooperating to build models that represent larger
areas. The zones depicted in Attachment 1 are either aligned with existing PC boundaries or boundaries of a group of
PCs with similar weather patterns.
Requirement R2 describes the need to select extreme benchmark temperature events necessary for the creation of
benchmark planning cases. Specifically, extreme hot and cold temperatures experienced during benchmark events
are assumed to be outside the ranges used as the basis of planning cases studied under Reliability Standard TPL-0015.1. Since temperature levels and associated weather conditions affect load levels, generation performance, and
transfer levels, the selection of benchmark events is critical to ensuring the Extreme Temperature Assessment
appropriately evaluates probable System conditions.
Since any region can experience temperatures that are higher or lower than normal, PCs within the same zone must
coordinate to select one common temperature event that includes hotter temperature assumptions and one
common temperature event that includes colder temperature assumptions. While it is understood that, for example,
one region may typically experience hotter summers and milder winters than another region, both a hotter than
average summer and a colder than average winter could result in reliability concerns. Therefore, the requirement is
for one common case specific to extreme heat and one common case specific to extreme cold conditions to be studied
for the Extreme Temperature Assessment. By selecting the same, common events, PCs ensure that extreme
temperatures are studied over the entire zone. The evaluation of a common event taking place over a wide area is
foundational to FERC Order No. 896. Furthermore, selecting the same, common events reasonably limits coordination
requirements. PCs are required to participate in the selection of events for their zone(s), but have no responsibilities
for the selection of events in other zones.
The SDT determined that the extreme heat and extreme cold temperatures selected must have a verified statistical
basis based on weather data from credible sources. The SDT has identified several key features that are used to
determine when a temperature event will constitute a valid extreme benchmark temperature event for the purposes
of completing the Extreme Temperature Assessment. Specifically, extreme benchmark temperature events must:
•

Consider no less than 40 years of temperature data,

•

Utilize data ending no more than five years prior to the time benchmark temperature events are selected,
and

•

Represent one of the worst 20 extreme temperature conditions within the zone.

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Requirement R2

Temperature events are ranked by computing the 3-day rolling average of daily maximum temperatures (for extreme
heat) or daily minimum temperatures (for extreme cold). The 3-day rolling average temperatures are calculated for
both extreme heat and extreme cold to identify multi-day periods of extreme heat or extreme cold temperature
events. The ERO will maintain a library of benchmark events to provide responsible entities access to vetted
benchmark temperature events that meet the criteria of Requirement R2. While selection of events from the ERO’s
provided library assures entities they are selecting valid events, Requirement R2 does not preclude entities from
collecting temperature data and identifying benchmark temperature events through their own process. Entities that
elect to develop their own benchmark temperature events are responsible for ensuring the input temperature data
and selected benchmark temperature events meet the criteria of Requirement R2. Additionally, because
Requirement R2 requires PCs within a zone to coordinate in the selection of the benchmark temperature events, the
process used to identify these events must be agreeable to those PCs.
The requirement to consider no less than 40 years of temperature data was established based on the observation
that many of the worst events identified in various regions of North America occurred in the 1980s and 1990s. For
example, preliminary data indicated that the five worst extreme cold temperature events in the PJM region over the
last 43 years occurred between 1983 and 1994. Similar results were seen in other regions for both extreme heat and
extreme cold temperature events. Thus, the SDT determined that a minimum of 40 years of temperature data should
be used to ensure more extreme events weren’t excluded by using a shorter duration of temperature data.

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Requirement R3
Requirement R3 aligns with directives in FERC Order No. 896, emphasizing the importance of coordinating the
development of benchmark planning cases and sensitivity cases amongst PCs within a zone, where the scope of
extreme temperature event studies will likely cover large geographical areas exceeding smaller individual planning
areas. The SDT considered comments from the industry expressing concerns regarding the necessity to coordinate
among all impacted PCs in developing benchmark planning cases and sensitivity cases for various extreme benchmark
temperature events. Recognizing that coordination among all impacted PCs may not be necessary to ensure reliability
within an individual planning area, the SDT drafted Requirement R3 to require each PC to coordinate with all PCs
within a zone to implement a process for the development of benchmark planning cases and sensitivity cases. The
SDT believes this change balances the need to ensure the planning cases capture impacts to/from entities affected
by the same benchmark temperature event, while recognizing that reliability will be less impacted by system changes
far removed from the zone.
PCs within a zone must coordinate to implement a process that results in the development of benchmark planning
cases that represent the benchmark temperature events selected in accordance with Requirement R2, and sensitivity
cases that demonstrate the impact of changes to the basic assumptions used in the benchmark planning cases. This
process requires several components, outlined in the sub-requirements of Requirement R3.
First, Requirement R3 Part 3.1 requires PCs within a zone to identify System models form the basis for developing the
benchmark planning cases. These models must represent one of the years in the Long-Term Transmission Planning
Horizon. PCs will also need to ensure models include stability modeling data to provide for the performance of
stability analysis later in the process. It is reasonably anticipated that PCs will likely utilize a summer peak model as
the starting point for the extreme heat benchmark temperature event and a winter peak model as the starting point
for the extreme cold benchmark temperature event.
Secondly, Requirement R3 Part 3.2 requires that PCs within a zone provide forecasted data for their area within the
zone that represents the benchmark temperature events selected in accordance with Requirement R2. Each PC must
provide data for their area within the zone that represents seasonal and temperature adjustments for Load,
generation, Transmission, and transfers. The provided data should be used to update the starting point models to
reflect the selected benchmark temperature events.
Thirdly, Requirement R3 Part 3.3 allows PCs to agree on assumptions for seasonal and temperature adjustments for
Load, generation, Transmission, and transfers in areas outside of the zone. As a sub-requirement of Requirement R3,
these assumptions must be coordinated among PCs in the zone, as needed. As an example, PCs within the zone may
identify the need for imported power during a benchmark event. The PCs may evaluate historical import availability
and assume an import from an area outside of the zone is reasonable and should be modeled.
Finally, Requirement R3 Part 3.4 requires PCs to coordinate and identify changes to generation, real and reactive
forecasted Load, or transfers that should be reflected in sensitivity cases. Sensitivity cases are intended to
demonstrate the impact of changes to the basic assumptions used in the benchmark planning cases, and Requirement
R3 Part 3.4 ensures PCs are cooperating to identify changes that sufficiently alter the assumptions reflected in the
benchmark planning cases. For example, PCs that identified an import external source to the zone for a benchmark
planning case may elect to alter the source of that import in the sensitivity case.

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Requirement R4
The SDT drafted Requirement R4 to require the responsible entity to use data consistent with Reliability Standard
MOD-032, supplemented by other sources as needed, for developing benchmark planning cases that represent
System conditions based on selected benchmark temperature events. This aligns with directives in FERC Order No.
896, paragraph 30, emphasizing the requirement of developing both benchmark planning cases and sensitivity study
cases. Requirement R4 is consistent with Reliability Standard TPL-001-5.1 in cross-referencing Reliability Standard
MOD-032, which establishes consistent modeling data requirements and reporting procedures for the development
of planning horizon cases necessary to support analysis of the reliability of the interconnected System. It is also
consistent with Reliability Standard TPL-001-5.1 in acknowledging that data from other sources may be required to
supplement the data collected through Reliability Standard MOD-032 procedures.
FERC Order No. 896, paragraph 116, directs NERC “to require in the new or modified Reliability Standard that
responsible entities model demand load response in their extreme weather event planning area”. This requirement
can be met via the use of data consistent with Reliability Standard MO-032, as included in the TPL-008-1 standard’s
Requirement R4. The modeling of the demand load response can be implemented through the use of MOD-032 in
which data needed for study base case development can be requested and obtained for development of the
benchmark planning cases and sensitivity cases.
Requirement R4 requires entities to use the coordination process developed in accordance with Requirement R3 to
develop the following four cases:
•

One common extreme heat benchmark planning case (Requirement R4 Part 4.1),

•

One common extreme cold benchmark planning case (Requirement R4 Part 4.1),

•

One common extreme heat sensitivity case (Requirement R4 Part 4.2), and

•

One common extreme cold sensitivity case (Requirement R4 Part 4.2).

At the completion of the case development process, implemented in accordance with Requirement R3, and executed
in Requirement R4, responsible entities will have the four cases listed above. This establishes category P0 as the
normal System condition in Table 1 for each case. Requirement R3 does not preclude PCs from implementing a
process that develops cases for multiple benchmark temperature events or additional sensitivity cases. Moreover,
entities may elect to develop additional cases for their internal use.
As per FERC Order No. 896, paragraph 94, it is clarified that resource adequacy benchmarks are not within the scope
of TPL-008-1. The intent of the standard is to evaluate benchmark events where sufficient generation is available to
supply load. However, under an extreme heat or extreme cold temperature condition, there may be instances where
the benchmark planning cases and/or sensitivity cases may not have sufficient available generation to supply the
load. In these scenarios, it may be acceptable for the responsible entity to revise the model to reduce the forecasted
Load, or include forecasted generation, to achieve a solution for the benchmark planning cases and/or sensitivity
cases and evaluate future Bulk Electric System performance for extreme temperature events. Each responsible entity,
as identified in Requirement R1, shall have dated evidence in either electronic or hard copy format that it developed
benchmark planning cases and sensitivity cases in accordance with Requirement R4.

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Requirement R5
Requirement R5 was drafted to require each responsible entity to set the criteria needed for limits that will be used
to evaluate System steady state voltage and post-Contingency voltage deviations for completing the Extreme
Temperature Assessment. The establishment of these criteria allows auditors to compare the results of the Extreme
Temperature Assessment with the established criteria.

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Requirement R6
Requirement R6 was drafted to require the responsible entity to define and document the criteria or methodology
used in evaluating the Extreme Temperature Assessment analysis to identify instability, uncontrolled separation, or
Cascading within an Interconnection. In developing planning benchmark as well as sensitivity cases for steady-state
and transient stability analyses, the Planning Coordinators and Transmission Planners typically use Interconnectionwide starting cases prior to further modifications to reflect the conditions of the benchmark events as well as
modifications for sensitivity cases. Analyses that may result in instability, uncontrolled separation, or Cascading
typically are confined within an Interconnection where generation and transmission Facilities are interconnected. It
is not expected that instability, uncontrolled separation, or Cascading that affect Facilities within an Interconnection
would impact other Interconnection(s) as these systems are asynchronous systems (i.e., not connecting
synchronously). Adequate and thorough criteria should be built into the Extreme Temperature Assessment to help
identify instability, uncontrolled separation, and Cascading conditions. The establishment of these criteria allows
auditors to compare the results of the Extreme Temperature Assessment with the established criteria.

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Requirement R7
This requirement addresses directives in FERC Order No. 896 to define a set of Contingencies that responsible entities
will be required to consider when conducting wide-area studies of extreme heat and cold weather events. FERC’s
preference to rely on established Contingency definitions, “[w]e believe that it is necessary to establish a set of
common contingencies for all responsible entities to analyze. Required contingencies, such as those listed in Table 1
of Reliability Standard TPL-001-5.1 (i.e., category P1 through P7), establish common planning events that set the
starting point for transmission system planning assessments,” was also considered by the SDT. It is necessary to
establish a set of common Contingencies for all responsible entities to analyze. Requiring the study of predefined
Contingencies, such as those listed in Table 1, will ensure a level of uniformity across planning regions, considering
that extreme heat and cold weather events often exceed the geographic boundaries of most existing planning
footprints. Defining the Contingencies in Table 1 consistently with Table 1 of Reliability Standard TPL-001-5.1 meets
FERC’s preference for commonality.
If feasible, all Contingencies listed in Table 1 should be considered for evaluation by the responsible entity; however,
the language affords flexibility in identifying the most appropriate Contingencies. As such, the responsible entity
should implement a method and establish sufficient supporting rationale to ensure Contingencies within each
category of Table 1, that are expected to produce more severe System impacts within its planning area, are
adequately identified. It is noted that since the benchmark planning cases are developed from the extreme
temperature benchmark events, they already represent extreme System conditions and thus not all Contingencies
from Reliability Standard TPL-001-5.1 Table 1 are included in the TPL-008-1 Table 1 for assessment. The Events
included in TPL-008-1 Table 1 represent the more likely Contingencies to occur.
The SDT included categories P0, P1, and P7 in Table 1 of TPL-008-1. The SDT finds it reasonable to exclude P2, P3, P4,
P5 and P6 Contingencies from the Extreme Temperature Assessment. Studying categories P0, P1 and P7 is the
minimum requirement of TPL-008-1. The standard does not preclude entities from studying additional Contingencies
if desired. The following discusses the rationale for excluding P2 through P6 Contingencies for TPL-008-1:
1. Excluding P2 and P4 Contingencies:
After consideration of comments received from the industry, the SDT removed P2 and P4 Contingencies due
to lower probability of occurrence than P1 and P7 Contingencies. TPL-008 now focuses on the single
Contingencies (P1) or multiple Contingencies on common structure (P7) that are more likely to be monitored
in operational scenarios. P2 Contingencies (e.g. Contingencies caused by internal breaker fault, bus section
fault, opening line section without a fault), and P4 Contingencies (e.g., Contingencies caused by stuck
breaker), while plausible under extreme temperature conditions, occur in much less frequency when
compared to P1 and P7 Contingencies. The standard establishes minimum requirement for Contingencies
with higher probability of occurrence. To the extent that the responsible entity determines the need for
studying beyond the minimum requirements, the standard does not preclude the entity from doing so.
2. Excluding P3 and P6 Contingencies:
Part of the decision stems from the complexity of P3 and P6 Contingencies, which involve multiple element
outages triggered by multiple Contingencies, with System adjustments allowed between them.
Consequently, the occurrence likelihood of P3 and P6 Contingencies could be even lower compared to P1
and P7 Contingencies. Moreover, aligning with the directives set forth in FERC Order 896, which emphasizes
the importance of incorporating derated generation, transmission capacity, and the availability of generation
and transmission in the development of benchmark planning cases, it becomes imperative for responsible
entities to consider potential concurrent or correlated generation and transmission outages and/or derates
within relevant benchmark planning cases. This ensures that the benchmark planning case accurately reflects
System conditions under extreme temperatures, with generation and transmission derates and/or outages

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14

Requirement 7

already factored. Therefore, the SDT believes excluding P3 and P6 is justified, as generation and transmission
derates and/or outages are already accounted for within the benchmark planning cases.
3. Excluding P5 Contingencies:
After consideration of comments received from the industry, the SDT removed P5 Contingency (Delayed Fault
Clearing due to failure of non-redundant component of a Protection System). This is because while some
categories of Contingencies may be assessed in a straightforward approach, category P5 Contingency events
often require a significant level of engineering analysis (including protection and/or control analysis). These
analyses are sensitive to the System topology and expected dispatch. As the planning benchmark cases are
developed for TPL-008-1 that represent System conditions that are different than the typical summer or
winter peak conditions, the development of category P5 Contingency events is expected to be a significant
burden. Since these events only require evaluations of possible mitigations (and not Corrective Action Plans),
violations resulting from these events are unlikely to result in significant transmission System investment.
Furthermore, any violations resulting from category P5 events may be mitigated by eliminating and
addressing the single point of failure included in the event definition. Thus, the evaluation of possible actions
is unlikely to result in further insight beyond the general reliability improvements associated with eliminating
single points of failure.
The SDT discussed and decided to keep the P7 Contingency category because common structure Contingencies are
often evaluated after categories P0 and P1 as the most common minimum level of transmission reliability assessment.
These events have a high likelihood of occurrence due to the following reasons:
•

Historical events that include simultaneous forced outage due to tripping of the double-circuit power lines
due to electrical storm events;

•

Environment-caused factors include pollution buildup, such as dust, that could cause faulted condition that
trips both transmission lines on a common tower;

•

Avian-caused outages that impact both transmission lines on a common tower;

•

Smoke from nearby wildfires can cause simultaneous tripping of both circuits on a common tower;

•

Nearby wildfires can impact System Operation as System Operators proactively de-energize both lines on a
common tower to avoid further impact to the transmission grid in the event of a simultaneous tripping of
both lines that may be carrying high power transfer between areas;

•

Weather-related causes such as lightning, flooding, wind, or icing can cause tripping of both transmission
lines on a common tower;

•

Natural disaster such as winter storm can cause transmission tower to collapse, taking out both lines strung
on the same tower;

•

Other incidents such as vehicle accident, aircraft accident, vandalism, or animal contact that can adversely
impact both transmission lines on the common tower.

Loss of two circuits running in parallel, simultaneously, is likely to have a greater system impact versus loss of two
unrelated or geographically separated circuits. Therefore, there is greater potential for reliability concerns,
especially during heavy transfers that are likely during periods of extreme weather, due to loss of both circuits of a
double-circuit line. Due to the reasons above, Contingencies that involve double-line circuits on a common tower
are included in the critical multiple Contingency list in either transmission planning or System Operations reliability
assessment.
Some, but not all, items to consider when developing the rationale for selecting Contingencies are:
NERC | Technical Rationale and Justification for TPL-008-1 | December 2024
15

•

Past studies,

•

Subject matter expert knowledge of the responsible entity’s System (to be supplemented with data or
analysis), and

•

Historical data from past operating events.

Lastly, regarding the Bulk Electric System (BES) voltage levels for the Contingencies, the SDT reviewed previous major
wide-area benchmark events and found that the Facilities that were out of service by these events have voltages that
are 200 kV and above. Thus, it is the reason for establishing voltages of 200 kV and above for Contingencies in Table
1 of TPL-008-1. The monitoring of potential impact is still applicable to Facilities with all BES voltage levels. However,
with that said, the SDT recognized that many PCs and TPs have Contingencies that include all BES levels. Responsible
entities may elect to use the existing Contingencies that they already have and report the criteria violations for the
categories in TPL-008-1 Table 1.

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Requirement R8
Requirement R8 was drafted to provide clarity on the following:
1. What planning study cases are required?
The Requirement R8 includes the following number of assessments to complete the Extreme Temperature
Assessment and address FERC Order No. 896 directives per paragraph 111 that “direct NERC to require in
the proposed new or modified Reliability Standard that responsible entities perform both steady state and
transient stability (dynamic) analyses in the extreme heat and cold weather planning studies”. In addition,
Requirement R8 also addresses FERC Order No. 896 directives per paragraph 124 that “require the use of
sensitivity cases to demonstrate the impact of changes to the assumptions used in the benchmark planning
case”. Requirement R8 also addresses FERC Order No. 896 directives per paragraph 124 that sensitivity
cases “should consider including conditions that vary with temperature such as load, generation, and
system transfers.” Since the benchmark planning case(s) already include System conditions under extreme
heat or extreme cold events, the sensitivity analysis is to include changes to at least one of the following
conditions: generation, real and reactive forecasted Load, or transfers. Since the minimum requirement
includes changes to one of these conditions, the PCs and the TPs can include further sensitivity assessments
to change more conditions if they choose to do so.
The following provides the number of assessments required for the benchmark planning and sensitivity
cases to complete the Extreme Temperature Assessment.
Type of Extreme
Temperature
Assessment

Extreme Cold Temperature
Event

Extreme Heat
Temperature Event

Total

Benchmark Planning
Case Analysis

One extreme cold
benchmark planning case
assessment

One extreme heat
benchmark planning case
assessment

Two benchmark
planning case
assessments

Sensitivity Case
Analysis

One sensitivity case with
changes to at least one of
the following conditions:
generation, real and
reactive forecasted Load,
or transfers

One sensitivity case with
changes to at least one of
the following conditions:
generation, real and
reactive forecasted Load,
or transfers

Two sensitivity case
assessments

Total

A total of four
assessments to
complete the
Extreme
Temperature
Assessment

2. What are the types of analyses required?
There are two types of analyses required: steady-state and transient stability. Each type of analysis must be
completed for each of the four cases described in the table above. This requirement is to satisfy FERC Order
No. 896 directive paragraph 111.

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Requirement R9
FERC Order No. 896 identifies a deficiency in the existing Reliability Standard TPL-001-5.1 where “planning
coordinators and transmission planners are required to evaluate possible actions to reduce the likelihood or mitigate
the consequences of extreme temperature events but are not obligated to develop corrective action plans” (¶139).
Given potential severe consequences of extreme cold and extreme heat events, FERC Order No. 896 raises the bar
and “directs NERC to require in the new or modified Reliability Standard the development of extreme weather
corrective action plans for specified instances when performance standards are not met” (¶152).
Due to higher likelihood of categories P0 and P1, these categories are held to a higher performance requirement in
benchmark planning cases. Corrective Action Plans are required to address performance deficiencies for categories
P0 and P1 in benchmark planning cases analyzed in the Extreme Temperature Assessment.
Furthermore, having a Corrective Action Plan requirement for categories P0 and P1 in benchmark planning cases
ensures resilience during future extreme cold and extreme heat temperature events, when the transmission System
is required to be P1 Contingency-secure (for steady-state and transient stability).
Given that a category P0 represents a continuous System condition without any system disturbances, the SDT
determined that load shedding should not be considered as a Corrective Action Plan. However, the SDT has
determined that load curtailment may be considered for a P1 Contingency as a Corrective Action Plan where load
shed is allowed to prevent system-wide failures and ensuring the continued operation of essential services under a
critical P1 Contingency in the extreme heat and cold temperature events. The SDT also emphasizes that alternative
solutions, other than firm load curtailment, are evaluated in higher priorities. Non-Consequential Load Loss is
permitted as an interim solution in situations that are beyond the control of the Planning Coordinator or Transmission
Planner that prevent the implementation of a Corrective Action Plan in the required timeframe; however, the
responsible entity must document the situation causing the problem, alternatives evaluated, and take actions to
resolve the situation. Future revisions to the Corrective Action Plan are allowed, provided that the planned Bulk
Electric System continues to meet the performance requirements of Table 1.
FERC Order No. 896 also directs NERC “to develop certain processes to facilitate interaction and coordination with
applicable regulatory authorities or governing bodies responsible for retail electric service as appropriate in
implementing a corrective action plan” (¶152). In the event that Non-Consequential Load Loss is included in the
Corrective Action Plan for a P1 Contingency, the responsible entity shall document alternative(s) considered, make
the Corrective Action Plan available to, and solicit feedback from, applicable regulatory authorities or governing
bodies responsible for retail electric service issues.
Lastly, the standard also permits the responsible entities to revise or update the Corrective Action Plan that was
considered and approved in the previous Extreme Temperature Assessment. This allows responsible entities to
incorporate approved mitigation measures from other planning assessments, such as annual transmission reliability
assessment under TPL-001-5 or subsequent related planning standard, or from other planning assessments for policydriven or economic needs. The revised or updated Corrective Action Plan associated with TPL-008-1 can be
documented as an addendum to the previous Extreme Temperature Assessment’s Corrective Action Plan.

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Requirement R10
The requirement for responsible entities to evaluate and document possible actions designed to reduce the likelihood
or mitigate the consequences and adverse impacts when the study results in the benchmark planning cases analyses
conclude there could be instability, uncontrolled separation, or Cascading for P7 Contingencies is in response to
directives outlined in FERC Order No. 896.
P7 Contingencies involve multiple element outages resulting from a single event, making them relatively less likely to
occur, compared to categories P0 and P1, but potentially causing more severe system impacts. Considering both the
likelihood of these Contingencies, and the fact that the Extreme Temperature Assessment already addresses lowprobability System conditions, the SDT determined that Corrective Action Plans should not be required for P7
Contingencies. However, due to the potential severity resulting from single-Contingency multiple element outages,
the SDT believes it is appropriate for responsible entities to at least evaluate and document possible mitigation
actions to reduce the likelihood or mitigate the consequences and adverse impacts of the event(s) when analyses
conclude there could be instability, uncontrolled separation, or Cascading. The biggest benefit from the evaluation
and documentation of the possible mitigating actions is it allows a responsible entity to see where major reliability
concerns exist that may need to be addressed; and, if a sufficiently large number of reliability concerns are identified,
it may encourage transmission upgrade mitigation option(s) to be considered and implemented without it being
strictly called for in the standard. Not requiring Corrective Action Plans for these Contingencies, but requiring the
evaluation, is a compromise from having Corrective Action Plans for all studied Contingencies.
Furthermore, FERC Order No. 896 requires “the use of sensitivity cases to demonstrate the impact of changes to the
assumptions used in the benchmark planning case” (¶124). FERC Order No. 896 also states: “NERC should determine
whether corrective action plans should be required for single or multiple sensitivity cases, and whether corrective
action plans should be developed if a contingency event that is not already included in benchmark planning case
would result in cascading outages, uncontrolled separation, or instability” (¶158). The SDT acknowledges that
sensitivity analysis is an important component of a robust transmission planning study. A requirement to develop
and implement Corrective Action Plans for sensitivity cases may incentivize responsible entities to select fewer or
less severe sensitivities. An incentive to select fewer sensitivities is undesirable because sensitivity study results are
used to identify constraints and initiate deeper analysis into the variables that impact those constraints. The study
results of sensitivity cases are also important to inform the development of Corrective Action Plans in the benchmark
planning cases. Therefore, the SDT determined the responsible entity must evaluate and document possible actions
designed to reduce the likelihood or mitigate the consequences and adverse impacts of the event(s) when analyses
of sensitivity cases conclude there could be instability, uncontrolled separation, or Cascading for categories P0, P1,
and P7. Finally, TPL-008-1 does not preclude the responsible entity from developing Corrective Action Plans for
sensitivity cases beyond what is required in the standard.

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Requirement R11
The requirement for responsible entities to share Extreme Temperature Assessment results aligns with directives in
FERC Order No. 896, emphasizing coordination and sharing of study findings. It ensures collaboration among
stakeholders and timely dissemination of critical information to entities with reliability-related needs. This fosters a
collective understanding of reliability concerns identified in wide-area studies, thereby enhancing overall grid
reliability.

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Attachment 1: Extreme Temperature Assessment Zones
The map depicts an approximation of the zones to be used in the Extreme Temperature Assessment and is provided
as a visual aid for each Planning Coordinator to identify the zone(s) to which the Planning Coordinator belongs to
under Attachment 1. The zone topology is a function of balancing authority jurisdiction and general knowledge of
zonal weather patterns, or in some cases, are limited by transmission constraints, or lack of transmission thereof,
between zones. The goal of the topology was to split the North American System into several distinct zones that have
similar electric power system properties (i.e., balancing authority and interconnections) and similar weather or
climatological patterns. Balancing authorities with large areas of jurisdiction, exclusively ISOs and RTOs, are assigned
their own weather zone. In geographical areas comprised of multiple balancing authorities, generalized weather
zones are created to best represent zonal weather patterns.
The NPCC region of the Eastern Interconnection was divided into New England, New York, Quebec Interconnection,
Ontario, and Maritimes. The Planning Coordinators for the NPCC region of the Eastern Interconnection are listed
below:
•

New England: Planning Coordinators in NPCC that primarily serve the six New England States.

•

New York: Planning Coordinators in NPCC that primarily serve New York.

•

Quebec: Planning Coordinators that primarily serve Quebec in the NPCC Region.

•

Ontario: Planning Coordinators in NPCC that primarily serve Ontario.

•

Maritimes: Planning Coordinators in NPCC that primarily serve New Brunswick, Nova Scotia, Prince Edward
Island, and the Northern Maine Independent System Administrator (NMISA). The NMISA is responsible for
the administration of the northern Maine transmission system and electric power markets in Aroostook and
Washington counties, with the load served radially from New Brunswick. It was not included in the New
England division since there are no physical transmission ties between NMISA and ISO-NE which is the
Planning Coordinator serving the remainder of the six New England States.

Additionally, SERC combined NERC Assessment areas of SERC-East, SERC-Central, and SERC-Southeast into a single
zone based on climate similarities. Northwest Regions, WECC-SW, SERC, and SERC-FP were based on balancing
authority PNNL data. SPP-N, SPP-S, MISO-N, and MISO-S were aggregated based on county-level PNNL data.

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Exhibit F
Analysis of Violation Risk Factors and Violation Severity Levels

RELIABILITY | RESILIENCE | SECURITY

Violation Risk Factor and Violation Severity Level
Justifications

Project 2023-07 Transmission System Planning Performance Requirements for
Extreme Weather
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 2023-07 Transmission System Planning Performance Requirements for Extreme Weather. 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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

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
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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

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 Justifications for TPL-008-1, Requirement R1
Proposed VRF

Lower

NERC VRF Discussion

A VRF of Lower is appropriate due to the fact that the Planning Coordinators, in conjunction with its
Transmission Planner(s) will determine joint responsibilities for requirements throughout TPL-008-1.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

5

VSLs for TPL-008-1, Requirement R1
Lower

Moderate

High

Severe

The responsible entity completed
its individual and joint
responsibilities such that the
Extreme Temperature Assessment
was completed, but it was
completed less than or equal to six
months late.

The responsible entity completed
its individual and joint
responsibilities such that the
Extreme Temperature Assessment
was completed, but it was
completed more than six months
but less than or equal to 12 months
late.

The responsible entity completed
its individual and joint
responsibilities such that the
Extreme Temperature Assessment
was completed, but it was
completed more than 12 months
but less than or equal to 18 months
late.

The Planning Coordinator, in
conjunction with its Transmission
Planner(s), failed to identify
individual and joint responsibilities
for completing the Extreme
Temperature Assessment.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

OR
The responsible entity completed
its individual and joint
responsibilities such that the
Extreme Temperature Assessment
was completed, but it was
completed more than 18 months
late.

6

VSL Justifications for TPL-008-1, Requirement R1
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the Planning Coordinator and Transmission Planner to determine
who completes the responsibilities throughout TPL-008-1. The responsibilities documentation will either be
developed or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

7

VRF Justifications for TPL-008-1, Requirement R2
Proposed VRF

High

NERC VRF Discussion

A VRF of high is appropriate due to the fact that selecting a benchmark event to perform an extreme
temperature assessment can affect the grid based on planning analysis for future events.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

8

VSLs for TPL-008-1, Requirement R2
Lower
N/A

Moderate
N/A

High

Severe

The Planning Coordinator
coordinated with all Planning
Coordinators within each identified
zone to identify one common
extreme heat and one common
extreme cold benchmark
temperature event for completing
the Extreme Temperature
Assessment, but one of the
identified events failed to meet all
the criteria of Requirement R2.

The Planning Coordinator
coordinated with all Planning
Coordinators within each identified
zone to identify one common
extreme heat and one common
extreme cold benchmark
temperature event for completing
the Extreme Temperature
Assessment, but both of the
identified events failed to meet all
of the criteria of Requirement R2.
OR
The Planning Coordinator failed to
coordinate with all Planning
Coordinators within each identified
zone to identify one common
extreme heat and one common
extreme cold benchmark
temperature event for completing
the Extreme Temperature
Assessment.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

9

VSL Justifications for TPL-008-1, Requirement R2
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

This VSL has been assigned as a binary due to the benchmark event needing to be selected for benchmark
planning cases to be completed. You either select a benchmark event or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

10

VRF Justifications for TPL-008-1, Requirement R3
Proposed VRF

Medium

NERC VRF Discussion

A VRF of medium is appropriate due to the fact that it is important to develop and maintain System models
within an entity’s planning area for performing Extreme Temperature Assessments. Connecting to MOD-032 to
provide important data needed to assist entities with System models is also important for accurate information
to be used.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

11

VSLs for TPL-008-1, Requirement R3
Lower
N/A

Moderate
N/A

High
N/A

Severe
The Planning Coordinator did not
coordinate with all Planning
Coordinators within each of its
identified zone(s) to implement a
process for developing benchmark
planning cases.
OR
The Planning Coordinator
coordinated with all Planning
Coordinators within each of its
identified zone(s) to implement a
process for developing benchmark
planning cases, but the process did
not include all of the required
elements.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

12

VSL Justifications for TPL-008-1, Requirement R3
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either develops and maintains the System
models within its planning area or it does not develop and maintain the System models within its planning area.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

13

VRF Justifications for TPL-008-1, Requirement R4
Proposed VRF

High

NERC VRF Discussion

The VRF of High is appropriate because it could directly affect the electrical state or capability of the BPS if
coordination is not completed for benchmark planning cases and sensitivity cases for the Extreme Temperature
Assessment results.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

14

VSLs for TPL-008-1, Requirement R4
Lower
N/A

Moderate
N/A

High
N/A

Severe
The responsible entity, as identified
in Requirement R1, did not use the
process developed in Requirement
R3 to develop benchmark planning
cases or sensitivity cases.
OR
The responsible entity, as identified
in Requirement R1, used the
process developed in Requirement
R3 to develop benchmark planning
cases and sensitivity cases, but did
not use data consistent with that
provided in accordance with the
MOD-032 standard, supplemented
by other sources as needed, for
one or more of the required cases.
OR
The responsible entity, as identified
in Requirement R1, used the
process developed in Requirement
R3 and data consistent with that
provided in accordance with the
MOD-032 standard, supplemented
as needed, but failed to develop
one or more of the required
planning or sensitivity cases.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

15

VSL Justifications for TPL-008-1, Requirement R4
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the Planning Coordinator to develop and implement a process for
coordinating the development of benchmark planning cases. The benchmark planning cases will either be
developed and implemented or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

16

VRF Justifications for TPL-008-1, Requirement R5
Proposed VRF

Medium

NERC VRF Discussion

A VRF of medium is appropriate due to the importance of having criteria for acceptable System steady state
voltage limits of post-Contingency voltage deviations for performing Extreme Temperature Assessments.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

17

VSLs for TPL-008-1, Requirement R5
Lower
N/A

Moderate
N/A

High
N/A

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

Severe
The responsible entity, as identified
in Requirement R1, did not have
criteria for acceptable System
steady state voltage limits and
post-Contingency voltage
deviations for completing the
Extreme Temperature Assessment.

18

VSL Justifications for TPL-008-1, Requirement R5
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either having acceptable criteria for System
steady state voltage limits and post-contingency voltage deviations or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

19

VRF Justifications for TPL-008-1, Requirement R6
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate due to the importance of defining and documenting the criteria or methodology for
System instability, uncontrolled separation, or Cascading.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

20

VSLs for TPL-008-1, Requirement R6
Lower
N/A

Moderate
N/A

High
N/A

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

Severe
The responsible entity, as identified
in Requirement R1, failed to define
or document the criteria or
methodology to be used in the
Extreme Temperature Assessment
to identify instability, uncontrolled
separation, or Cascading within an
Interconnection.

21

VSL Justifications for TPL-008-1, Requirement R6
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

22

VRF Justifications for TPL-008-1, Requirement R7
Proposed VRF

Medium

NERC VRF Discussion

A VRF of medium is appropriate for this requirement. Identifying Contingencies for performing Extreme
Temperature Assessments for each of the event categories in Table 1 can indirectly impact the BES.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

23

VSLs for TPL-008-1, Requirement R7
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity, as identified
in Requirement R1, identified
Contingencies for each category in
Table 1 that are expected to
produce more severe System
impacts on its portion of the Bulk
Electric System, but did not include
the rationale for those
Contingencies selected for
evaluation as supporting
information.

The responsible entity, as identified
in Requirement R1, did not identify
Contingencies for each category in
Table 1 that are expected to
produce more severe System
impacts on its portion of the Bulk
Electric System.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

24

VSL Justifications for TPL-008-1, Requirement R7
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

25

VRF Justifications for TPL-008-1, Requirement R8
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate due to the importance of performing an Extreme Temperature Assessment every 5
years.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

26

VSLs for TPL-008-1, Requirement R8
Lower

Moderate

High

Severe

The responsible entity, as identified
in Requirement R1, completed
steady state and transient stability
analyses in the Extreme
Temperature Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for one
or more sensitivity cases in
accordance with Requirement R8.

The responsible entity, as identified
in Requirement R1, completed
steady state and transient stability
analyses in the Extreme
Temperature Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for one
or more benchmark planning cases
in accordance with Requirement
R8.

The responsible entity, as identified
in Requirement R1, completed
steady state and transient stability
analyses in the Extreme
Temperature Assessment using the
Contingencies identified in
Requirement R7, but failed to
document results for one or more
of the sensitivity cases in
accordance with Requirement R8.

The responsible entity, as identified
in Requirement R1, completed
steady state and transient stability
analyses in the Extreme
Temperature Assessment using the
Contingencies identified in
Requirement R7, but failed to
document results for one or more
of the benchmark planning cases in
accordance with Requirement R8.
OR
The responsible entity, as identified
in Requirement R1, failed to
complete steady state or transient
stability analyses and document
results in the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, in accordance
with Requirement R8.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

27

VSL Justifications for TPL-008-1, Requirement R8
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

28

VRF Justifications for TPL-008-1, Requirement R9
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate for this requirement. Developing a Corrective Action Plan is important to the BES as
it assists entities when Systems are unable to meet performance requirements.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

29

VSLs for TPL-008-1, Requirement R9
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity, as identified
in Requirement R1, developed a
Corrective Action Plan in
accordance with Requirement R9,
but failed to make its Corrective
Action Plan available to, or solicit
feedback from, applicable
regulatory authorities or governing
bodies responsible for retail
electric service issues.

The responsible entity, as identified
in Requirement R1, failed to
develop a Corrective Action Plan
when the benchmark planning case
study results indicate the System is
unable to meet performance
requirements for the Table 1 P0 or
P1 Contingencies.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

OR
The responsible entity, as identified
in Requirement R1, developed a
Corrective Action Plan, but it was
missing one or more of the
elements of Requirement R9 Part
9.1, 9.3 and 9.4 (as applicable).

30

VSL Justifications for TPL-008-1, Requirement R9
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either having acceptable criteria for System
steady state voltage limits and post-contingency voltage deviations or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

31

VRF Justifications for TPL-008-1, Requirement R10
Proposed VRF

Lower

NERC VRF Discussion

A VRF of lower has been assigned to Requirement R10. Documenting possible actions to reduce the likelihood
or mitigate the consequences and adverse impacts are administrative in nature.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

32

VSLs for TPL-008-1, Requirement R10
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity, as identified
in Requirement R1, evaluated and
documented possible actions to
reduce the likelihood or mitigate
the consequences and adverse
impacts of the event(s) when
analyses conclude there could be
instability, uncontrolled separation,
or Cascading within an
Interconnection where required
under Requirement R10 Part 10.1,
but failed to evaluate and
document possible actions where
required under Requirement R10
Part 10.2.

The responsible entity, as identified
in Requirement R1, evaluated and
documented possible actions to
reduce the likelihood or mitigate
the consequences and adverse
impacts of the event(s) when
analyses conclude there could be
instability, uncontrolled separation,
or Cascading within an
Interconnection where required
under Requirement R10 Part 10.2,
but failed to evaluate and
document possible actions where
required under Requirement R10
Part 10.1.
OR
The responsible entity, as identified
in Requirement R1, failed to
evaluate and document possible
actions to reduce the likelihood or
mitigate the consequences and
adverse impacts of the event(s)
when analyses conclude there
could be instability, uncontrolled
separation, or Cascading within an
Interconnection where required
under Requirement R10 Parts 10.1
and 10.2.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

33

VSL Justifications for TPL-008-1, Requirement R10
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the fact that the responsible entity will have evaluated and
documented possible actions to mitigate adverse impacts.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

34

VRF Justifications for TPL-008-1, Requirement R11
Proposed VRF

Medium

NERC VRF Discussion

The VRF of Medium is appropriate because it could directly affect the electrical state or capability of the BES if
entities are not aware of the results from its Extreme Temperature Assessment results.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

35

VSLs for TPL-008-1, Requirement R11
Lower

Moderate

High

Severe

The responsible entity, as identified
in Requirement R1, provided its
Extreme Temperature Assessment
results to functional entities having
a reliability related need who
requested the information in
writing, but it was more than 60
days but less than or equal to 80
days following the request.

The responsible entity, as identified
in Requirement R1, provided its
Extreme Temperature Assessment
results to functional entities having
a reliability related need who
requested the information in
writing, but it was more than 80
days but less than or equal to 100
days following the request.

The responsible entity, as identified
in Requirement R1, provided its
Extreme Temperature Assessment
results to functional entities having
a reliability related need who
requested the information in
writing, but it was more than 100
days but less than or equal to 120
days following the request.

The responsible entity, as identified
in Requirement R1, provided its
Extreme Temperature Assessment
results to functional entities having
a reliability related need who
requested the information in
writing, but it was more than 120
days following the request.
OR
The responsible entity, as identified
in Requirement R1, did not provide
its Extreme Temperature
Assessment results to functional
entities having a reliability related
need who submitted a written
request for the information.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

36

VSL Justifications for TPL-008-1, Requirement R11
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

37

Exhibit G
Summary of Development History and Complete Record of Development

RELIABILITY | RESILIENCE | SECURITY

Summary of Development History
The following is a summary of the development record for proposed Reliability Standard
TPL-008-1.
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. 2 For this project, the SDT consisted of industry experts,
all with a diverse set of experiences. A roster of the Project 2023-07 SDT members is included in
Exhibit H.
II.

Standard Development History
A. Project 2023-07 Transmission System Planning Performance Requirements for
Extreme Weather
On June 15, 2023, the Commission issued Order No. 896 3 directing NERC to develop

modifications to Reliability Standard TPL-001-5.1 or a new Reliability Standard to address a need
for long-term planning requirements for extreme heat and cold weather events. Accordingly,
proposed Reliability Standard TPL-008-1 was developed to comply with associated regulatory
directives from Order No. 896.

Section 215(d)(2) of the Federal Power Act; 16 U.S.C. § 824(d)(2).
The NERC Standard Processes Manual is available at
https://www.nerc.com/FilingsOrders/us/RuleOfProcedureDL/SPM_Clean_Mar2019.pdf.
3
Order No. 896, Transmission System Planning Performance Requirements for Extreme Weather, 183
FERC ¶ 61,191 (2023).
1
2

1

B. Standard Authorization Request Development
On July 19, 2023, the Standards Committee accepted the Project 2023-07 Standards
Authorization Request (“SAR”) and authorized posting the SAR for a 30-day informal comment
period and the solicitation of drafting team members. 4
C. Standards Committee Authorizes Procedural Waiver
On December 13, 2023, the Standards Committee authorized a waiver of Sections 4.9 and
4.12 of the Standard Processes Manual to meet the FERC deadlines for this project. The waiver
authorized NERC to reduce the initial formal comment and ballot periods for Project 2023-07 from
45 days to as little as 25 days, with ballot pools formed in the first 10 days and initial ballot and
non-binding polls conducted during the last 10 days of the comment period. Additional formal
comment and ballot periods were reduced from 45 days to as few as 15 days with ballots conducted
during the last 5 days of the comment period. The final ballot was reduced from 10 days to as little
as 5 days. 5
D. First Posting – Comment Period, Initial Ballot, and Non-binding Poll
On March 20, 2024, the Standards Committee authorized the initial posting of proposed
Reliability Standard TPL-008-1 and associated Implementation Plan and other associated
documents for a 45-day formal comment period. 6 The initial posting took place from March 20,
2024 through May 3, 2024, with a parallel initial ballot and non-binding poll on the Violation Risk
Factors (“VRFs”) and Violation Severity Levels (“VSLs”) held during the last 10 days of the
NERC, Meeting Minutes – Standards Committee Meeting (July 19, 2023),
https://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/July%20Meeting%20Minutes%20%20Approved%20August%2023,%202023.pdf.
5
NERC, Meeting Minutes – Standards Committee Meeting (Dec. 13, 2023),
https://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/SC%20December%20Minutes%20%20Approved%20January%2017,%202024.pdf.
6
NERC, Meeting Minutes – Standards Committee Meeting (Mar. 20, 2024),
https://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/SC_Meeting_MinutesMarch_2024.pdf.
4

2

comment period from April 24, 2024 through May 3, 2024. 7 The initial ballot for proposed
Reliability Standard TPL-008-1 received 18.69 percent approval, reaching quorum at 88.22
percent of the ballot pool, and the initial ballot for the associated Implementation Plan received
30.03 percent approval with 87.9 percent quorum. 8 The non-binding poll for the associated VRFs
and VSLs received 16.67 percent supportive opinions, reaching quorum at 88.22 percent of the
ballot pool. 9 There were 78 sets of responses, including comments from approximately 179
different individuals and approximately 99 companies, representing all 10 industry segments. 10
E. Second Posting – Comment Period, Additional Ballot, and Non-binding Poll
The second draft of proposed Reliability Standard TPL-008-1, the associated
Implementation Plan, and other associated documents were posted for a 38-day formal comment
period from July 16, 2024 through August 22, 2024, with a parallel additional ballot and nonbinding poll held from August 13, 2024 through August 22, 2024. 11 The additional ballot for
proposed Reliability Standard TPL-008-1 received 18.17 percent approval, reaching quorum at
87.9 percent of the ballot pool, and the additional ballot for the associated Implementation Plan
received 31.97 percent approval with 87.58 percent quorum. 12 The non-binding poll for the
associated VRFs and VSLs received 20.71 percent supportive opinions, reaching quorum at 86.87
percent of the ballot pool. 13

There were 74 sets of responses, including comments from

approximately 191 different individuals and approximately 118 companies, representing all 10
industry segments. 14

7
8
9
10
11
12
13
14

See exhibit G, Complete Record of Development, at items 16, 19.
Id. at items 21, 22.
Id. at item 23.
Id. at item 18.
Id. at items 33, 36.
Id. at items 38, 39.
Id. at item 40.
Id. at item 35.

3

F. Third Posting - Comment Period, Initial Ballot, and Non-binding Poll
The third draft of proposed Reliability Standard TPL-008-1, the associated Implementation
Plan, and other associated documents were posted for a 15-day formal comment period from
October 7, 2024 through October 21, 2024, with a parallel additional ballot and non-binding poll
held from October 11, 2024 through October 21, 2024. 15 The additional ballot for proposed
Reliability Standard TPL-008-1 received 51.9 percent approval, reaching quorum at 84.39 percent
of the ballot pool, and the additional ballot for the associated Implementation Plan received 63.34
percent approval with 84.08 percent quorum. 16 The non-binding poll for the associated VRFs and
VSLs received 55.19 percent supportive opinions, reaching quorum at 83.84 percent of the ballot
pool. 17 There were 66 sets of responses, including comments from approximately 156 different
individuals and approximately 101 companies, representing all 10 industry segments. 18
G. Fourth Posting- Comment Period, Initial Ballot, and Non-binding Poll
The fourth draft of proposed Reliability Standard TPL-008-1, the associated
Implementation Plan, and other associated documents were posted for a 15-day formal comment
period from November 7, 2024 through November 21, 2024, with a parallel additional ballot and
non-binding poll held from November 12, 2024 through November 21, 2024. 19 The additional
ballot for proposed Reliability Standard TPL-008-1 received 73.71 percent approval, reaching
quorum at 83.12 percent of the ballot pool, and the additional ballot for the associated
Implementation Plan received 77.72 percent approval with 83.12 percent quorum. 20 The nonbinding poll for the associated VRFs and VSLs received 73.4 percent supportive opinions,

15
16
17
18
19
20

Id. at items 50, 54.
Id. at items 55, 56.
Id. at item 57.
Id. at item 52.
Id. at items 68,71.
Id. at items 73,74.

4

reaching quorum at 84.18 percent of the ballot pool. 21 There were 50 sets of responses, including
comments from approximately 140 different individuals and approximately 89 companies,
representing all 10 industry segments. 22
H. Final Ballot
The final draft of proposed Reliability Standard TPL-008-1 was posted for a 5-day final
ballot period from December 2, 2024 through December 6, 2024. 23 The final ballot for proposed
Reliability Standard TPL-008-1 reached quorum at 84.08 percent of the ballot pool, receiving
support from 75.43 percent of the voters. 24 The ballot for the Implementation Plan reached quorum
at 84.08 percent of the ballot pool, receiving support from 79.38 percent of the voters. 25
I. Board of Trustees Adoption
The NERC Board of Trustees adopted proposed Reliability Standard TPL-008-1 on
December 10, 2024. 26

Id. at item 75.
Id. at item 70.
23
Id. at item 87.
24
Id. at item 88.
25
Id. at item 89.
26
NERC, Board of Trustees Agenda Package Dec. 2024, Agenda Item 3b (Project 2023-07 – Transmission
System Planning Performance Requirements for Extreme Weather),
https://www.nerc.com/gov/bot/Agenda%20highlights%20and%20Mintues%202013/Board_Open_Meeting%20Age
nda%20Package%20-%20December%202024%20-%20ATT.pdf.
21
22

5

Complete Record of Development

6

Home > Program Areas & Departments > Standards > Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
​Related Files​
Status
The final ballots for TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events and its implementation plan concluded 8 p.m. Eastern, Friday, December 6, 2024​.​ The voting results can be accessed via
the links below. The standard will be submitted to the Board of Trustees for adoption and then filed with the appropriate regulatory authorities.​
​The Standards Committee approved waivers to the Standards Process Manual at their December 2023 meeting. These waivers were sought by NERC Standards for reduced formal comment and ballot periods to assist the drafting teams in expediting the standards
development process due to firm timeline expectations set by FERC Order 896. 
​Background
On June 15, 2023, FERC issued a Final Rulemaking to direct NERC to develop a new or modified Reliability Standard to address a lack of a long-term planning requirement(s) for extreme heat and cold weather events. Specifically, FERC directed NERC to develop
modifications to Reliability Standard TPL-001-5.1 or a new Reliability Standard, to require the following: (1) development of benchmark planning cases based on major prior extreme heat and cold weather events and/or meteorological projections; (2) planning for
extreme heat and cold weather events using steady state and transient stability analyses expanded to cover a range of extreme weather scenarios including the expected resource mix's availability during extreme heat and cold weather conditions, and including the
wide-area impacts of extreme heat and cold weather; and (3) development of corrective action plans that mitigate any instances where performance requirements for extreme heat and cold weather events are not met.​ In addition, FERC directed “NERC to submit a
new or modified Reliability Standard within 18 months of the date of publication of this final rule in the Federal Register," which equates to December 15, 2024.​
Standard Affected: TPL-001-5.1
Purpose/Industry Need
Consistent with FERC Order No. 896, the purpose of this project is to address the reliability gap pertaining to the consideration of extreme heat and cold weather events that exist in current transmission planning standards (e.g., NERC Reliability Standard TPL-001-5.1
– Transmission System Planning Performance Requirements).
Recent extreme weather events have shown the risk that such events can pose to the reliable operation of the BPS, and have highlighted the high risk to life and extreme economic impacts that can result from unplanned load shed during such conditions. The impact
of concurrent failures of BPS generation and transmission equipment and the potential for cascading outages that may be caused by extreme heat and cold weather events should be studied and corrective actions should be identified and implemented.
Subscribe to this project's observer mailing list 
Select "NERC Email Distribution Lists" from the "Service" drop-down menu and specify “Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather Observer List" in the Description Box.​

Draft

Actions

Dates

Results

​12/02/24 - 12/06/24​​

​Ballot Results

Consideration of
Comments

​

Final Ballots
(87) Info

(88) TPL-008-1

Vote​

​

Draft 4
TPL-008-1

Additional Ballot

(58) Clean | (59) Redline to Last Posted
(60) Implementation Plan​​

​

11/12/24 - 11/21/24

(73) TPL-008-1

(72) Info

(74) Implementation Plan

Supporting Materials
(61) Technical Rationale

​Ballot Results

Vote

​

(62) Unofficial Comment Form​
(63) VRF/VSL Justifications

​
(64) Consideration of FERC Order 896 Directives
Informational Materials
(65) TPL-008-1 ERO Benchmark Weather Event Development and Mai​ntenance Process
DRAFT​​
(66) Benchmark Event Data​​

Comment Period
(68) I​nfo

​11/07/24 - 11/21/24​

​

Submit Comments​​​

(67) TPL-008 Data Library Read Me

Draft 3
TPL-008-1
(41) Clean | (42) Redline to Last Posted
(43) Implementation Plan
Supporting Materials
(44) Technical Rationale
(45) Unofficial Comment Form​
(46) VRF/VSL Justifications​​
(47) Consideration of FERC Order 896 Directives
Informational Materials

Additional Ballot
​
(54) Info

Vote​​​

10/11/24 - 10/21/24

​Ballot Results
(55) TPL-008-1
(56) Implementation Plan
​

​

(52)

Comment Period
(50) Info

​10/07/24 - 10/21/24​

Consideration of Comments

​

Submit Comments​​​

​

​Ballot Results

Additional Ballot
​

8/13/24 - 8/22/24

(37) Info

(38) TPL-008-1
(39) Implementation Plan

Vote

​

Comment Period
(33) Info

Submit Comments​​

​

​

​

Ballot Results
4/24/24 - 5/3/24

(20) Info

(21) TPL-008-1
​

Vote

Join Ballot Pools​

Consideration of Comments

​

Initial Ballot
Draft 1

(35)

​7/16/24 - 8/22/24​

​

3/20/24 - 4/18/24

(18)Consideration of Comments

​Comment Period
​

3/20/24 - 5/3/24​​

​

Submit Comments​​
​

The ​Standards Committee accepted the
waiver on December 13, 2023.

(8)SAR

​The Standards Committee accepted the
SAR on July 19, 2023​.

(3) Standard Authorization
Request Supporting Materials
(4) Unofficial Comment Form (Word)

Drafting Team Nominations
Supporting Materials
(1) Unofficial Nomination Form (Word)

Comment Period
​

8/29/23 – 9/27/23

Submit Comments

​Nomination Period
​

Submit Nominations​​

​8/29/23 – 9/27/23

​

​

Do not use this form for submitting nominations

Unofficial Nomination Form

Project 2023-07 Modifications to TPL-001-5.1 Transmission System
Planning Performance Requirements for Extreme Weather
Drafting Team
General Information

Additional information is available on the project page. If you have questions, contact Manager of
Standards Development, Jamie Calderon (via email), or at 404-960-0568.
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 quality review team
experience is beneficial, but not required.

Project Information
Project Purpose

On June 15, 2023, FERC issued a Final Rulemaking to direct NERC to develop a new or modified Reliability
Standard to address a lack of a long-term planning requirement(s) for extreme heat and cold weather
events. Specifically, FERC directed NERC to develop modifications to Reliability Standard TPL-001-5.1 or a
new Reliability Standard, to require the following: (1) development of benchmark planning cases based on
major prior extreme heat and cold weather events and/or meteorological projections; (2) planning for
extreme heat and cold weather events using steady state and transient stability analyses expanded to
cover a range of extreme weather scenarios including the expected resource mix's availability during
extreme heat and cold weather conditions, and including the wide-area impacts of extreme heat and cold
weather; and (3) development of corrective action plans that mitigate any instances where performance
requirements for extreme heat and cold weather events are not met.
Standard(s) Affected

TPL-001-5.1

Nominee Expertise Requested

For this project, NERC is seeking individuals who possess experience in one or more of the following
areas:
•

Transmission planning assessments;

•

Steady state and dynamic stability analyses;

•

Sensitivity analysis;

•

Developing benchmark events and Interconnection wide planning cases.

Time Commitment Expectations
RELIABILITY | RESILIENCE | SECURITY

Time commitments for most projects include up to two face-to-face meetings per quarter (on average
two full working days each meeting) with conference calls scheduled as needed. Team members may
agree to individual or subgroup assignments, to work in separate meetings and present to the larger
team for discussion and review. Another important component of quality reviews and drafting team
efforts is outreach. Members of the team will be expected to conduct industry outreach during the
development process to support a successful project outcome.
Project Priority

Each project will be developed according to that project’s priority status. While each standard project
addresses particular industry needs, some projects will be identified as a higher priority project. A
higher priority project may initially include a strict timeline, which may be needed to effectively
respond to a FERC Directive or as determined by the NERC Board of Trustees. A higher priority project
may also need to increase the frequency of meetings at any time throughout the development
process to account for project timeline needs. Similarly, other priority projects may adjust to a lower
frequency of meetings throughout the development process to reallocate resources to high priority
projects.
This project has been identified as higher priority at this time. The project has a FERC deadline of
December 2024. To meet this deadline, the team will meet regularly, up to three times a week on
conference calls, with face-to-face meetings scheduled as the members’ schedule allows, up to once a
quarter.

Submitting Nominations

Do not use this form for submitting nominations. Use the electronic form to submit nominations for
Project 2023-07 Modifications to TPL-001-5.1 Transmission System Planning Performance Requirements
for Extreme Weather drafting team members by 8 p.m. Eastern, Wednesday, September 27, 2023. This
unofficial version is provided to assist nominees in compiling the information necessary to submit the
electronic form.

Name:
Organization:
Address:

Unofficial Nomination Form
Project 2023-07 Modifications to TPL-001-5.1 Transmission System Planning Performance Requirements for Extreme Weather
August 2023

2

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):
Acknowledgement that the nominee has read and understands both the NERC Participant Conduct
Policy and the Standard Drafting Team Scope documents, available on NERC Standards Resources.
Yes, the nominee has read and understands these documents.
Select each NERC Region in which you have experience relevant to the Project for which you are
volunteering:
MRO
NPCC
RF

SERC
Texas RE
WECC

NA – Not Applicable

Unofficial Nomination Form
Project 2023-07 Modifications to TPL-001-5.1 Transmission System Planning Performance Requirements for Extreme Weather
August 2023

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 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

Transmission Operator
Transmission Owner
Transmission Planner
Transmission Service Provider
Purchasing-selling Entity
Reliability Coordinator
Reliability Assurer
Resource Planner

Unofficial Nomination Form
Project 2023-07 Modifications to TPL-001-5.1 Transmission System Planning Performance Requirements for Extreme Weather
August 2023

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 2023-07 Modifications to TPL-001-5.1 Transmission System Planning Performance Requirements for Extreme Weather
August 2023

5

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Agenda Item 5a
Standards Committee
July 19, 2023

Standard Authorization Request (SAR)
Complete and submit this form, with attachment(s)
to the NERC Help Desk. Upon entering the Captcha,
please type in your contact information, and attach
the SAR to your ticket. Once submitted, you will
receive a confirmation number which you can use
to track your request.

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
Transmission System Planning Performance Requirements for Extreme
Weather
July 5, 2023

Mohammed Osman, Lead Engineer of System Analysis, Power System Analysis
William Lamanna, Senior Engineer – Reliability Assessments
Name:
Scott Barfield-McGinnis, Principal Technical Advisor, Power Risk Issues and Strategic
Management
Organization: NERC
Mohamed: 404-446-9634
[email protected]
Telephone:
Scott: 404-446-9689
Email:
[email protected]
William: 404-446-2568
[email protected]
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?):
The current transmission planning Reliability Standard TPL-001-5.1 – Transmission System Planning
Performance Requirements 1 does not expressly require transmission planners and planning
coordinators to consider extreme hot and cold weather in their transmission planning assessments. In
particular, Reliability Standard TPL–001–5.1, Table 1, provisions 2.f (stability) and 3.b (steady state)

1

TPL-001-5.1 at https://www.nerc.com/pa/Stand/Reliability%20Standards/TPL-001-5.1.pdf.

RELIABILITY | RESILIENCE | SECURITY

Requested information
require stability and steady state analyses, respectively, to be performed for certain traditional extreme
events, but does not expressly require them for extreme heat and cold conditions.
Extreme weather-related events that have spanned the continent in recent years demonstrate the
challenges associated with planning for extreme heat and cold weather events, particularly those events
that affect a wide area or that occur during periods when the Bulk-Power System (BPS) must meet
unexpected high demand. Extreme heat and cold weather events have occurred with greater frequency
in recent years, and are projected to occur with even greater frequency in the future. At the same time,
the changing resource mix has resulted in a grid that is increasingly more susceptible to the impacts of
extreme heat and cold weather events.
Recent extreme weather events have shown the risk that such events can pose to the reliable operation
of the BPS, and have highlighted the high risk to life and extreme economic impacts that can result from
unplanned load shed during such conditions. Long-term transmission planning, along with other
measures, can play an important role in identifying and helping to minimize these risks.
Accordingly, this project will revise the NERC transmission planning Reliability Standards, consistent
with FERC Order No. 896, 2 to address the study of extreme heat and cold conditions. The impact of
concurrent failures of BPS generation and transmission equipment and the potential for cascading
outages that may be caused by extreme heat and cold weather events should be studied and corrective
actions should be identified and implemented.
These standard(s) should use benchmark extreme heat and cold weather events for the required
studies, and require the development of planning cases with appropriate sensitivities over a wide-area.
The standard should also require the identification and implementation of corrective actions where
system performance requirements are not met, including appropriate coordination and communication
of studies.
Purpose or Goal (How does this proposed project provide the reliability-related benefit described
above?):
Consistent with FERC Order No. 896, this purpose of this project is to address the reliability gap
pertaining to the consideration of extreme heat and cold weather events that exist in current
transmission planning standards (e.g., NERC Reliability Standard TPL-001-5.1 – Transmission System
Planning Performance Requirements).
In Order No. 896, NERC was directed to develop a new or modified Reliability Standard (“Standard”)
that requires the following: (1) the development of benchmark planning cases based on information
such as major prior extreme heat and cold weather events and/or future meteorological projections; (2)
planning for extreme heat and cold weather events using steady state and transient stability analyses
expanded to cover a range of extreme weather scenarios, including expected availability of the resource
mix during extreme heat and cold weather conditions, and including the broad area impacts of extreme

Order No. 896, Transmission System Planning Performance Requirements for Extreme Weather, 183 FERC ¶ 61,191 (2023), available at
https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20230615-3100&optimized=false.
2

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

2

Requested information
heat and cold weather; and (3) the development of corrective action plans that mitigate specified
instances where performance requirements during extreme heat and cold weather events are not met.
Project Scope (Define the parameters of the proposed project):
The scope of the proposed project is to develop a new transmission planning Standard, or modify an
existing Standard, to address the directives from FERC Order No. 896 pertaining to the study of extreme
heat and cold events. New or revised definitions may be required. This project may also need to revise
Standard MOD-032-1 – Data for Power System Modeling and Analysis 3 for data sharing.
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 4 which 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):
The drafting team is responsible for the development of new Standard or the revision of Standard TPL001-5.1 that shall achieve the actions listed below related to addressing concerns pertaining to
transmission system planning for extreme heat and cold weather events outlined in the Order that
impact the Reliable Operation of the Bulk-Power System.
The technical justification of the reliability-related benefits of developing a new Standard, modified
Standard, or industry definition were addressed in the NOPR 5 and Order. The following actions have
been listed in a sequence consistent with the directives in the Order.
A. Develop New or Modified Standard
Develop a new or modified Standard 6 to require the following: 7
1. Development of benchmark planning cases based on major prior extreme heat and cold weather
events and/or meteorological projections;
2. Planning for extreme heat and cold weather events using steady state and transient stability
analyses expanded to cover a range of extreme weather scenarios including the expected
resource mix's availability during extreme heat and cold weather conditions, and including the
wide-area impacts of extreme heat and cold weather; and

See MOD-032-1 at https://www.nerc.com/pa/Stand/Reliability%20Standards/MOD-032-1.pdf.
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.
5 See Docket RM22-10-000, NOPR 179 FERC ¶ 61,195, document number 2022-13471 at
https://www.federalregister.gov/documents/2022/06/27/2022-13471/transmission-system-planning-performance-requirements-forextreme-weather.
6 Order at P25.
7 Order at P27.
3
4

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

3

Requested information
3. Development of corrective action plans that mitigate specified instances where performance
requirements for extreme heat and cold weather events are not met. 8
Also, identify the responsible entities for developing benchmark planning cases and conducting widearea studies.
B. Develop Benchmark Events and Planning Cases Based on Major Prior Extreme Heat and Cold
Weather Events and/or Meteorological Projections
The drafting team must consider approaches that would provide a uniform framework for developing
benchmark events while still recognizing regional differences. For example, consider defining
benchmark events around:
•

a projected frequency (e.g., 1-in-50-year event); or

•

a probability distribution (95th percentile event).

Although the NOPR did not specify how these benchmark events should be developed, the NOPR
provided two examples: (1) the drafting team could develop the benchmark event or events during the
standard development process; or (2) the drafting team could include in the new or modified Standard a
framework establishing a common design basis for the development of benchmark events. In
developing a new of modified Standard, responsible entities are to be required to:[57]
1. Develop extreme heat and cold weather benchmark events; 9
2. Develop benchmark planning cases based on identified benchmark events; and
3. Describe/define the types of heat and cold scenarios/events that responsible entities must
study. 10
For instance, a benchmark event could be constructed based on data from a major prior extreme heat
or cold event, with adjustments if necessary to account for the fact that future meteorological
projections may estimate that similar events in the future are likely to be more extreme. 11
The drafting must consider the examples of approaches for defining benchmark events identified in the
NOPR (e.g., the use of projected frequency or probability distribution). 12
The drafting must ensure that benchmark events that all responsible entities likely to be impacted by
the same extreme weather events use consistent benchmark events. Doing so is important to ensuring
that neighboring planning regions are assuming similar weather conditions and are able to coordinate

NOPR, 179 FERC ¶ 61,195 at P 51.
Benchmark events will form the basis for a planner's benchmark planning case— i.e., the base case representing system conditions under
the relevant benchmark event—that will be used to study the potential wide-area impacts of anticipated extreme heat and cold weather
events.
10 Order at P35.
11 NOPR, 179 FERC ¶ 61,195 at P47.
12 Order at P36.
8
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Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

4

Requested information
their assumptions accordingly. Allowing responsible entities significant discretion to determine the
applicable meteorological conditions would not meet the objectives of the Order. 13
Extreme heat and cold benchmark events must reflect regional differences in climate and weather
patterns. 14
The drafting team may and is encouraged to engage the national labs, RTOs, NOAA, and other agencies
and organizations in developing benchmark events. 15
To provide for a common design basis for responsible entities to follow when creating benchmark
planning cases, case are to represent: 16
1. Potential weather-related contingencies (e.g., concurrent/correlated generation and
transmission outages, derates) and expected future conditions of the system such as changes in
load:
2. Transfers;
3. Generation resource mix; and
4. Impacts on generators sensitive to extreme heat or cold (due to the weather conditions
indicated in the benchmark events).
The drafting team must ensure the new or modified Standard contains appropriate mechanisms for
ensuring the benchmark event reflects up-to-date meteorological data. A mechanism to update the
benchmark event at least every five years would strike a reasonable balance between the benefits of
using the most up-to-date meteorological data and administrative the burdens of collecting and
analyzing such data. 17
C. Defining “Wide-Area”
The drafting team in developing a new or modified Standard must include that transmission planning
studies consider the wide-area impacts of extreme heat and cold weather. 18 The drafting team should
consider approaches in defining “wide-area” over a geographical area consistent with weather and
electrically, and how these two approaches correlate. 19 The drafting team must clearly describe the
process that a responsible entity must use to define the wide-area boundaries. 20

Order at P37.
Order at P38.
15 Order at P37.
16 Order at P39.
17 Order at P40.
18 Order at P41.
19 Order at P47.
20 Order at P50.
13
14

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

5

D. Entities Responsible for Developing Benchmark Events and Planning Cases, and for Conducting
Transmission Planning Studies of Wide-Area Events
a. Entity Responsible for Establishing Benchmark Events
The Order directed NERC to develop requirements that address the types of extreme heat and
cold weather scenarios responsible entities are required to study, including the development of
benchmark events and benchmark planning cases.
The drafting team shall develop the new or modified Standard consistent with the approach the
Commission took in Order No. 779 (i.e., TPL-007-1 – Transmission System Planned Performance
for Geomagnetic Disturbance Events). Also, define mechanisms to periodically update extreme
heat and cold weather benchmark events. 21
The drafting team may use an existing functional entity or a group of functional entities (e.g., a
group of planning coordinators) to designate the tasks of developing benchmark planning cases
and conducting wide-area studies. 22
b. Entities Responsible for Development of Planning Cases and Conducting Transmission
Planning Studies of Wide-Area Events
The drafting team is to (1) designate the responsible entities responsible for developing
benchmark planning cases, and (2) specify which responsible entities have an obligation to
conduct wide-area studies under the new or modified Standard. 23
The drafting team may designate the tasks of developing benchmark planning cases and
conducting wide-area studies to an existing functional entity or a group of functional entities
(e.g., a group of planning coordinators). If needed, the drafting team may propose to establish a
new functional entity registration to undertake these tasks by working with NERC registration
and legal staffs. The drafting team, if considering such an approach, will need to consider that a
new functional registration will require a modification to the NERC Rules of Procedure, which
can take additional time to complete. 24
E. Coordination Among Registered Entities and Sharing of Data and Study
In determining the responsible entities that will be developing benchmark planning cases and
conducting wide-area studies, the drafting team must ensure there is a mechanism is place to ensure
the sharing of data and studies. For example, it is possible that the selected responsible entities under
the new or modified Standard will not be able to request and receive needed data pursuant to MOD–
032–1, absent modification to that Standard. 25
The drafting team must require system information and study results sharing and coordination among
planning coordinators and transmission planners with transmission operators, transmission owners, and
generator owners for extreme heat and cold weather events. 26
The drafting team must address wide-area coordination among giving due consideration to relevant
factors identified by commenters in the Order and NOPR 27,28 At a minimum, the drafting team must
require responsible entities to share the results of their wide-area studies with other registered entities

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

6

Requested information
consistent with TPL-00-1-5.1 (e.g., transmission operators, transmission owners, and generator owners
that have a reliability related need for the studies). 29
F. Concurrent/Correlated Generator and Transmission Outages
The drafting team must require the study of concurrent/correlated generator and transmission outages
due to extreme heat and cold events in benchmark events as described in more detail below. Previous
extreme weather events have demonstrated that there is a high correlation between generator outages
and cold temperatures, indicating that as temperatures decrease, unplanned generator outages and
derates increase. Because of this correlation, it is necessary that responsible entities evaluate the risk of
correlated or concurrent outages and derates of all types of generation resources and transmission
facilities as a result of extreme heat and cold events. Some generators may be unavailable under
extreme heat or cold conditions and thus their potential outages must be considered in extreme heat
and cold weather planning scenarios. The drafting team may strike a balance between allowing
responsible entities discretion to ensure the study incorporates their operating experience and the need
to create a robust framework that ensures extreme heat and cold events are adequately studied. 30
G. Conduct Transmission System Planning Studies for Extreme Heat and Cold Weather Events
1. Steady State and Transient Stability Analyses
In a steady state analysis, the system components are modeled as either in-service or out-ofservice and the result is a single point-in-time snapshot of the system in a state of operating
equilibrium. A transient stability (dynamic) analysis examines the system from the start to the
end of a disturbance to determine if the system regains a state of operating equilibrium.
Performing both analyses ensures that the system has been thoroughly assessed for instability,
uncontrolled separation, and cascading failures in both the steady state and the transient
stability realms.
The drafting team must require that responsible entities:
1. Perform both steady state and transient stability (dynamic) analyses in the extreme heat
and cold weather planning studies (in the long-term planning horizon 31);

Order at P59. See also Order No. 779 at https://www.federalregister.gov/documents/2016/09/30/2016-23441/reliability-standard-fortransmission-system-planned-performance-for-geomagnetic-disturbance-events.
22 Order at P62.
23 Order at P60.
24 Order at P62.
25 Order at P73.
26 Order at P65.
27 See Appendix A, P81 and P82 for additional information.
28 See Appendix B, P57, P64, and P70.
29 Order at P77.
30 Order at P88 through P91.
31 Order at P95.
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Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

7

Requested information
2. Define a set of contingencies that responsible entities will be required to consider when
conducting wide-area studies of extreme heat and cold weather events under the new or
modified Standard;
3. Develop specific criteria for determining which outages should be considered in the
benchmark planning case; and
4. Model demand load response in their extreme weather event planning area. 32
2. Sensitivity Analysis
Sensitivity analyses help a transmission planner to determine if the results of the base case are
sensitive to changes in the inputs. The use of sensitivity analyses is particularly necessary when
studying extreme heat and cold events because some of the assumptions made when
developing a base case may change if temperatures change. For example, during extreme cold
events, load may increase as temperatures decrease, while a decrease in temperature may
result in a decrease in generation. 33
In developing sensitivities the drafting must:
1. Require the use of sensitivity cases to demonstrate the impact of changes to the
assumptions used in the benchmark planning case; and
2. Establish a baseline set of sensitivities for the new or modified Standard. FERC stated that
while it would not require the inclusion of any specific sensitivity in Order No. 896, NERC
should consider including conditions that vary with temperature such as load,
generation, and system transfers. 34
3. Modifications to the Traditional Planning Approach
The drafting team must require the use of planning methods that ensure adequate consideration
of the broad characteristics of extreme heat and cold weather conditions that also address:
1. Whether probabilistic elements can be incorporated into the new or modified Standard
and implemented presently by responsible entities, and
2. Identify any probabilistic planning methods that would improve upon existing planning
practices, but are infeasible to include in a new or modified Standard at this time. 35
H. Implement a Corrective Action Plan if Performance Standards Are Not Met
The Order specifies that NERC must develop standards that require Corrective Action Plans that include
mitigation for any instances where performance requirements for extreme heat and cold events are not

Order at P111 through P116.
Order at P124 and also at P126.
34 Order at P124.
35 Order at P134, P138, and P158.
32
33

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

8

met; therefore, the drafting must require the development of extreme weather corrective action plans
that:
1. Identify specified instances when performance standards are not met;
2. Require certain processes to facilitate interaction and coordination with applicable regulatory
authorities or governing bodies responsible for retail electric service as appropriate in
implementing a corrective action plan;
3. Require mitigation for specified instances where performance requirements for extreme heat
and cold events are not met (i.e., when certain studies conducted under the Standard show that
an extreme heat or cold event would result in cascading outages, uncontrolled separation, or
instability);
4. Determine whether corrective action plans should be required for single or multiple sensitivity
cases;
5. Determine whether corrective action plans should be developed if a contingency event that is
not already included in benchmark planning case would result in cascading outages,
uncontrolled separation, or instability;
6. Establish required study contingencies and baseline sensitivities for which a corrective action
plan is required; and
7. Require that responsible entities share their corrective action plans with, and solicit feedback
from, applicable regulatory authorities or governing bodies responsible for retail electric service
issues. 36
I. Other Extreme Weather-Related Events and Issues
Reliability Standard Implementation Timeline
NERC must submit a responsive Reliability Standard to FERC by December 23, 2024.
The proposed implementation timeline for a new or modified Reliability Standard must have an
implementation beginning no later than 12 months after the effective date of a Commission order
approving the proposed new or modified Reliability Standard. 37
The drafting team in developing the standard has the discretion to develop a phased-in implementation
timeline for the different requirements of the proposed Reliability Standard (i.e., developing benchmark
cases, conducting studies, developing corrective action plans, etc.). However, this phased-in
implementation must begin within 12 months of the effective date of a Commission order approving
the proposed Reliability Standard and must include a clear deadline for implementation of all
requirements. 38
Other
There is a concern that there is limited modeling of protection systems in dynamic assessments
currently, and any dynamic simulation of extreme events would require significant modeling of
protection systems to provide for convergence of the numerical simulation. The drafting team in
developing the planning requirements for extreme heat and cold weather must take into account any

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

9

Requested information
deficiencies in dynamic modeling of protection systems. The dynamics databases used for transient
stability simulations by various interconnections typically do not include comprehensive dynamic
models of relays installed in the interconnection. The drafting team should consider wide-area
applications by various interconnections that may not typically include comprehensive dynamic models
of relays installed in the interconnection. 39
The drafting team should consider the cost impacts to responsible entities.
Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated
with the proposed project):
The cost impact is unknown and will be considered during drafting team meetings. However, The SAR
proposes to either create a new Standard or modify an existing Standard(s) that would require
responsible entities to create Corrective Action Plans to address risks related to transmission system
planning performance for extreme weather directed in the Order. The costs associated are anticipated
to be comparable to those associated with a responsible entity’s performance of TPL-007-1 –
Transmission System Planned Performance for Geomagnetic Disturbance Events.
Please describe any unique characteristics of the BES facilities that may be impacted by this proposed
standard development project (e.g., Dispersed Generation Resources):
BES facilities may be uniquely impacted by the results of improved studies that incorporate enhanced
extreme heat and cold weather scenarios and sensitivity analyses performed by the transmission
planners. Mitigating and corrective actions may require transmission system topology changes,
including but not limited to re-evaluating load shedding plans as a safety net in response to high
demand in extreme heat and cold weather over a wide-area. For example, if studies reveal thermal
violations that could be anticipated during extreme weather, transmission facilities may need to be
upgraded.
Generation facilities may be impacted by having to change the way concurrent or coincident generator
outages are managed and planned to reduce the likelihood of not meeting high demands over a widearea. For example, if multiple generators are disrupted due to pipeline issues and don’t have dual fuel
capability.
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):
The development of a new or modified Standard should consider drafting team individuals from the
following functional entities: Balancing Authority, Generator Owner, Planning Coordinator, Reliability
Coordinator, Transmission Owner, and Transmission Planner.

Order at P152 through P158, and P165.
Order at P188.
38 Order at P193.
39 Order at P68 and P74.
36
37

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

10

Requested information
Do you know of any consensus building activities 40 in connection with this SAR? If so, please provide any
recommendations or findings resulting from the consensus building activity.
In Order No. 896, FERC highlighted that industry experts agreed that extreme weather events are likely
to become more severe and frequent in the future and there is a need to address them in the long-term
planning horizon.
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)?
TPL-001-5.1a and MOD-032-1.
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.
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.

Enter
(yes/no)
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.

40

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

11

Market Interface Principles
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.

Yes
Yes
Yes

Identified Existing or Potential Regional or Interconnection Variances
Region(s)/
Explanation
Interconnection
e.g., NPCC
No needed Regional or Interconnection variances were identified. The Order did
acknowledge that the drafting team consider approaches that would provide a
uniform framework for developing benchmark events while still recognizing regional
differences in climate and weather patterns, among other considerations; therefore,
the use of region is considered to be the common geographical understanding and
not NERC Regional Entity footprints. The Commission disagreed that Regional Entities
and reliability coordinators should not lead the development of benchmark events
and that the drafting team should. 41

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

41

Date

Owner

Change Tracking

1

June 3, 2013

Revised

1

August 29, 2014

Standards Information Staff

Updated template

2

January 18, 2017

Standards Information Staff

Revised

Order at P58.

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

12

2

June 28, 2017

Standards Information Staff

Updated template

3

February 22, 2019

Standards Information Staff

Added instructions to submit via Help
Desk

4

February 25, 2020

Standards Information Staff

Updated template footer

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

13

Appendix A
Excerpts from NOPR, 179 FERC ¶ 61,195
P51. February 2011 Southwest Cold Weather Event and January 2014 Polar Vortex Cold Weather Event
81. While balancing authorities and other entities must share system information and study results with
their transmission and planning coordinator pursuant to Reliability Standards MOD-032-1 and TPL-001-5.1
as described above, there is no required sharing of such information—or required coordination—among
planning coordinators and transmission planners with transmission operators, transmission owners, and
generator owners, thus limiting the benefits of additional modeling. Sharing system information and study
results and enhancing coordination among these entities for extreme heat and cold weather events could
result in more representative planning models by better:
(1) integrating and including operations concerns ( e.g., lessons learned from past issues including
corrective actions and projected outcomes from these actions, evolving issues concerning extreme
heat/cold) in planning models; and
(2) conveying reliability concerns from planning studies ( e.g., potential widespread cascading,
islanding, significant loss of load, blackout, etc.) as they pertain to extreme heat or cold.
82. Therefore, as part of its revisions, NERC should require system information and study results sharing,
and coordination among planning coordinators and transmission planners with transmission operators,
transmission owners, and generator owners for extreme heat and cold weather events. To better
understand the benefits of the suggested actions, we are inviting comments on:
(1) the parameters and timing of coordination and sharing;
(2) specific protocols that may need to be established for efficient coordination practices; and
(3) potential impediments to the proposed coordination efforts.

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

14

Appendix B
Excerpts from Order No. 896
57. Environmental Defense Fund (EDF), Tri-State, and Eversource Energy Service Company (Eversource)
propose that reliability coordinators should have the responsibility to perform wide-area planning and
coordination in collaboration with other impacted reliability coordinators
64. there is no required sharing of such information related to extreme heat or cold weather events—or
required coordination—among planning coordinators and transmission planners with transmission
operators, transmission owners, and generator owners. Sharing system information and study results and
enhancing coordination among these entities for extreme heat and cold weather events could result in
more representative planning models by better integrating and including operations concerns ( e.g.,
lessons learned from past issues including corrective actions and projected outcomes from these actions,
evolving issues concerning extreme heat/cold) in planning models; and conveying reliability concerns
from planning studies ( e.g., potential widespread cascading, islanding, significant loss of load, blackout,
etc.) as they pertain to extreme heat or cold. 42
70. Tri-State suggests that the balancing authority should address the results of the studies and how they
should communicate those results among the transmission planners. Tri-State also asserts that the
balancing authority is responsible for resource adequacy and should communicate resource needs for the
area with the responsible transmission planners who can evaluate system needs and “provide access to
remove” resource needs.

42

NOPR at P81.

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

15

Unofficial Comment Form

Project 2023-07 Modifications to TPL-001-5.1 Transmission System
Planning Performance Requirements for Extreme Weather
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on Project 2023-07 Modifications to TPL-001-5.1 Transmission System
Planning Performance Requirements for Extreme Weather Standard Authorization Request (SAR) by 8
p.m. Eastern, Wednesday, September 27, 2023.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Manager of
Standards Development, Jamie Calderon (via email), or at 404-960-0568.
Background Information

On June 15, 2023, FERC issued a Final Rulemaking to direct NERC to develop a new or modified Reliability
Standard to address a lack of a long-term planning requirement(s) for extreme heat and cold weather
events. Specifically, FERC directed NERC to develop modifications to Reliability Standard TPL-001-5.1 or a
new Reliability Standard, to require the following: (1) development of benchmark planning cases based on
major prior extreme heat and cold weather events and/or meteorological projections; (2) planning for
extreme heat and cold weather events using steady state and transient stability analyses expanded to
cover a range of extreme weather scenarios including the expected resource mix's availability during
extreme heat and cold weather conditions, and including the wide-area impacts of extreme heat and cold
weather; and (3) development of corrective action plans that mitigate any instances where performance
requirements for extreme heat and cold weather events are not met.

RELIABILITY | RESILIENCE | SECURITY

Questions

1. What technical considerations should the drafting team consider to assist with the development of
benchmark planning cases per the Order?
Comments:

2. What Contingencies and scenarios should the drafting team consider to represent extreme
weather events per the Order?
Comments:
3. What potential variants for extreme heat and cold weather events should the drafting team
consider that are 1) representative of different planning areas, and 2) assure reasonable
consistency between planning areas?
Comments:
4. Provide any additional comments for the SAR drafting team to consider, if desired.
Comments:

Unofficial Comment Form
Project 2023-07 Modifications to TPL-001-5.1 Transmission System Planning Performance Requirements | August 2023

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Summary Response to SAR Comments

NERC Project 2023-07 Transmission System Planning Performance
Requirements for Extreme Weather
October 2023
Comments Received Summary

There were 31 sets of responses, including comments from approximately 93 different people from
approximately 81 companies representing 10 of the Industry Segments as shown in the table on the
following pages.
A summary of comments submitted can be reviewed on the project page. If you have an interest in joining
the distribution list for this project, please reach out to standards developer, Jordan Mallory.
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 Director of Standards Latrice Harkness (via email) or at (404) 446-9728.
Consideration of Comments

The NERC Project 2023-07 thanks all of industry for your time and comments. The standard drafting team
(SDT) feels that many great points have been provided for the SDT to consider during the drafting phase of
this project. High level themes received from industry are located below (bolded is the high-level theme
followed by the SDT’s response).
Addressed in TPL-001-5.1
FERC Order 896 Paragraph 5 states: "...Reliability Standard TPL-001-5.1 was developed to establish
transmission system planning performance requirements that ensure that the Bulk-Power System operates
reliably over a broad spectrum of system conditions and following a wide range of probable contingencies.
Both it and its successor, TPL-001-5.1, include provisions for transmission planners and planning
coordinators to study system performance under extreme events based on their experience; however,
neither standard specifically requires entities to conduct performance analysis for extreme heat and cold
weather, despite the fact that such conditions have clearly demonstrated a risk to the Reliable Operation
of the Bulk-Power System, thus leaving a reliability gap in system planning." To address the reliability gap,
FERC has directed NERC to modify an existing or create a new Reliability Standard by December 2024.
Confine scope of project w here ex trem e w eather w ill be ex perienced and consider regional
variances.
Paragraph 3 of FERC Order 896, which states: "…planners cannot simply project historical weather patterns
forward to effectively forecast the future, since climate change has made the use of historical weather
observations no longer representative of future conditions. For example, extreme summer heat in regions
like the Pacific Northwest and extreme winter cold in regions like Texas have increased demand for
electricity at times when historically demand has been low. As events such as these will likely continue to

RELIABILITY | RESILIENCE | SECURITY

present challenges in the future, transmission planners and planning coordinators must account for this
new reality in their planning processes." The SAR has been drafted at an appropriate level to ensure all
regions are prepared for continued future climate change and/or the SDT has the flexibility to draft regional
variances should the team decide this route is needed.
Guidance on ex trem e heat and cold w eather events
The SDT will focus on extreme heat and extreme cold weather conditions during this project. Please see
FERC Order 896 for additional details regarding examples and further details on extreme heat and
extreme cold weather. Order No. 896, Transmission System Planning Performance Requirements for
Extreme Weather, 183 FERC ¶ 61,191 (2023), available at FERC Order 896 (link).

Specifically, Paragraph 2: “We take this action to address challenges associated with planning for extreme
heat and cold weather events, particularly those that occur during periods when the Bulk-Power System
must meet unexpectedly high demand. Extreme heat and cold weather events have occurred with greater
frequency in recent years and are projected to occur with even greater frequency in the future. These
events have shown that load shed during extreme temperature results in unacceptable risk to life and have
extreme economic impact. As such, the impact of concurrent failures of Bulk-Power System generation and
transmission equipment and the potential for cascading outages that may be caused by extreme heat and
cold weather events should be studied and corrective actions should be identified and implemented.” The
SDT will take your comment into consideration during the drafting phase of this project.”
In addition, paragraphs 20–24 in FERC Order 896 provide examples of the major extreme heat and extreme
cold weather.
“Extreme weather-related events that spread across large portions of the country over the past decade
demonstrate the challenges to transmission planning from extreme heat and cold weather patterns.
The NOPR discussed seven major extreme heat and cold weather events that had occurred since 2011.
Of these, four (2011, 2013, 2018, and 2021) were extreme cold weather events that nearly caused
system collapse if the operators had not acted to shed load. The remaining three events (2014, 2020,
and 2021) were extreme heat weather events that resulted in generation losses and varying degrees of
load shedding. Since the issuance of the NOPR, another extreme cold weather event indicated reliability
challenges faced by the Bulk-Power System. In December 2022, Winter Storm Elliott caused extreme
cold conditions that significantly stressed the Bulk-Power System, forcing some utilities to deploy rolling
blackouts to preserve Bulk-Power System reliability. These extreme heat and cold events demonstrate
a risk to Reliable Operation of the Bulk-Power System. These conditions have created an urgency to
address the negative impact of extreme weather on the reliability of the Bulk-Power System. To that
end, the directives to NERC in this final rule aim to improve system planning specifically for extreme
heat and cold weather events. The potential impact of widespread extreme heat and cold events on
the reliability of the Bulk-Power System can be modeled and studied in advance as part of near-term
and long-term transmission system planning. Responsible entities could then use the studies to develop
transmission system operational strategies or corrective action plans with mitigations that could be
deployed in preparation for extreme heat and cold events. The current transmission planning Reliability
Standards, however, do not obligate transmission planners and planning coordinators to consider

Summary Response to SAR Comments – October 2023

2

extreme hot and cold weather in their transmission assessments. In particular, Reliability Standard TPL001-5.1 requires steady state and stability analyses to be performed for certain extreme events but
does not require steady state and stability analyses for extreme heat and cold conditions. Likewise,
while Reliability Standard TPL-001-5.1 Table 1, provisions 2.f (stability) and 3.b (steady state), requires
responsible entities to study events based on operating experience that may result in a wide-area
disturbance, the Standard does not specify the study of extreme heat or cold conditions. While widearea extreme heat and cold weather events may not occur every year, their frequency and magnitude
are expected to increase. The National Oceanic and Atmospheric Administration’s (NOAA) data and
analyses show an increasing trend in extreme heat and cold weather events, and the U.S. Environmental
Protection Agency climate change indicators also show upward trends in heatwave frequency, duration,
and intensity. NOAA states that climate change is also driving more compound events, i.e., multiple
extreme events occurring simultaneously or successively, such as concurrent heat waves and droughts,
and more extreme heat conditions in cities.”
Narrow scope to focus on ex trem e cold w eather and lesser ex tend heat
NERC was directed to address extreme cold and extreme heat weather events. Based on the events stated
in the FERC Order, the SDT determined that the SAR is drafted at the appropriate level regarding the extent
of extreme heat events to be addressed during the drafting phase of this project. See FERC Order 896
Paragraph 20:

“…The remaining three events (2014, 2020, and 2021) were extreme heat weather events that
resulted in generation losses and varying degrees of load shedding.”
Consider a new standard.
The team will consider all possible paths during the drafting phase of this project. A new standard will be a
part of that consideration.
R evise TPL-001
The team will consider all possible paths during the drafting phase of this project. Revisions to TPL-001 will
be part of that consideration.
Consider how GM D (TPL-007) w as drafted for the layout of this standard.
The team will consider all possible paths during the drafting phase of this project and will take a look at how
TPL-007 was drafted as guidance.
Use FER C/ NER C reports and regional analysis.
The SDT will use the FERC/NERC report and other analysis/reports to assist with data gathering and
determination of drafting requirements and/or determining benchmarks.
Consider alignm ent m ethods, term inology, and tim efram es in EOP-012 standard.
The SDT will consider methods, terminology, and timeframes in EOP-012 standard during the drafting phase
of this project.
Avoid one size fits all standard.

Summary Response to SAR Comments – October 2023

3

The SDT acknowledges that a one size fits all may be complicated when it comes to weather condition
assessments and will consider this during the drafting phase of this project.
Frequency of event (1 in 25-year event)
Duration of frequency will be discussed and determined by the SDT during the drafting phase of this project.
R each out to R TO/ I SO, National Laboratories, NOAA, and other agencies.
The SDT plans to involve the respective agencies to assist in discussion around meteorological projections
and/or other respective areas when it comes to developing suggested benchmarks for this project.
Use ex trem e heat or cold w eather conditions rather than ex trem e events.
The SDT will consider usage of terms during the drafting phase of this project.
Consider realistic schedules for data preparation and perform ing of the scenario planning
study.
The SDT will consider preparation and performing schedules during the drafting phase of this project.
Various recom m endations on 1 in 10 load scenario, specific criteria as to w hat constitutes
ex trem e w eather dem and (ex am ple, dem and ex pected at a 90-10 w eather scenario, or a once
in 31-year w eather, or a 3 standard deviation w eather tem perature or dem and ex pected in a
90-10 w eather scenario, once in 31-year w eather, or a 3-standard deviation in w eather
tem perature), etc.
The SDT will consider all these recommendations during the drafting phase of this project.
Define “benchm ark event” and/ or “w ide area”
Possible NERC glossary of terms like “benchmark event” or “wide area,” etc. will be discussed and
determined by the SDT during the drafting phase of this project.
Other ex trem e w eather events (i.e., w ind, w ildfire, hurricanes, hum idity, etc.)
Due to the tight turnaround of this project, this SDT will keep its focus on extreme heat and extreme cold
weather. Notes will be taken regarding other extreme weather discussed during this project. Additional
considerations outside of this scope can be considered for a later drafting team. Lastly, there is nothing that
precludes an entity from studying extreme events that would pose a risk to the BPS.
Narrow scope to BES instead of BPS
The SDT determined to keep the scope of extreme heat and extreme cold weather events to what FERC
Order 896 focuses on, which is the BPS. See Paragraph 1 of FERC Order 896.

“…the Commission directs the North American Electric Reliability Corporation (NERC), the
Commission-certified Electric Reliability Organization (ERO), to submit a new Reliability Standard or
modifications to Reliability Standard TPL-001-5.1 that addresses concerns pertaining to transmission

Summary Response to SAR Comments – October 2023

4

system planning for extreme heat and cold weather events that impact the Reliable Operation 1 of
the Bulk-Power System. 2”
Overlap w ith other TPL SDT
Each SDT has been provided with a scope of work, which does not overlap with one another. This team will
focus on drafting requirements that focus on benchmarking planning for extreme heat and extreme cold
events. The Standards Developers are in close coordination with one another as modifications are made to
the TPL standards.
Lead by PCs w ith input from TP s. Avoid piling on too m any coincident im probable contingencies
w hich w ould not produce useful results.
The SDT will take this into consideration during the drafting phase of this project.
TOs and GOs input to contingency developm ent.
The SDT will take this into consideration during the drafting phase of this project.
Standard should specify scenarios.
The SDT will take this into consideration during the drafting phase of this project.
Lim it sensitivity to the m ost im pactful scenarios w ithin the planning region.
Consistent with your comment, in FERC Order 896, the Commission states: "We also direct NERC to include
in the Reliability Standard the framework and criteria that responsible entities shall use to develop from
the relevant benchmark event planning cases to represent potential weather-related contingencies (e.g.,
concurrent/correlated generation and transmission outages, derates) and expected future conditions of
the system such as changes in load, transfers, and generation resource mix, and impacts on generators
sensitive to extreme heat or cold, due to the weather conditions indicated in the benchmark events."

Limiting considerations to specific seasonal conditions conflicts with the directive that both extreme heat
and cold weather events should be considered. The SDT will consider these variants (sensitivities) into
account during the drafting phase of this project.
Ex trem e w eather variant definition flex ibility needed to allow P C and TP to utilize judgm ent.
The SDT will take this into consideration during the drafting phase of this project.
Consider CAPs for 300 kV and above.
The SDT will take this into consideration during the drafting phase of this project.
CAP s should be for several independent contingencies, rather than one specific contingency.
1

The FPA defines “Reliable Operation” as “operating the elements of the Bulk-Power System within equipment and electric system thermal,
voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden
disturbance, including a cybersecurity incident, or unanticipated failure of system elements.” 16 U.S.C. 824o(a)(4).
2 The Bulk-Power System is defined in the FPA as “facilities and control systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof), and electric energy from generating facilities needed to maintain transmission system reliability.
The term does not include facilities used in the local distribution of electric energy.” Id. 824o(a)(1).

Summary Response to SAR Comments – October 2023

5

The SDT will take this into consideration during the drafting phase of this project.
I nconsistency w ith SAR - identifies CAPs are required to prevent cascading and therm al
overloads. Cascading is consistent w ith TP L-001, but therm al overloads are not.
The SDT sought clarification from the folks who drafted this project’s SAR. This project is to focus on events
that could trigger cascading conditions.
Ex pand on "cost im pacts" in SAR - perform ing analysis or CAPs. Per SAR , cost is unknow n and
w ill be considered by SDT.
The SDT will take this into consideration during the drafting phase of this project.

Summary Response to SAR Comments – October 2023

6

Agenda Item 5a
Standards Committee
July 19, 2023

Standard Authorization Request (SAR)
Complete and submit this form, with attachment(s)
to the NERC Help Desk. Upon entering the Captcha,
please type in your contact information, and attach
the SAR to your ticket. Once submitted, you will
receive a confirmation number which you can use
to track your request.

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
Transmission System Planning Performance Requirements for Extreme
Weather
July 5, 2023

Mohammed Osman, Lead Engineer of System Analysis, Power System Analysis
William Lamanna, Senior Engineer – Reliability Assessments
Name:
Scott Barfield-McGinnis, Principal Technical Advisor, Power Risk Issues and Strategic
Management
Organization: NERC
Mohamed: 404-446-9634
[email protected]
Telephone:
Scott: 404-446-9689
Email:
[email protected]
William: 404-446-2568
[email protected]
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?):
The current transmission planning Reliability Standard TPL-001-5.1 – Transmission System Planning
Performance Requirements 1 does not expressly require transmission planners and planning
coordinators to consider extreme hot and cold weather in their transmission planning assessments. In
particular, Reliability Standard TPL–001–5.1, Table 1, provisions 2.f (stability) and 3.b (steady state)

1

TPL-001-5.1 at https://www.nerc.com/pa/Stand/Reliability%20Standards/TPL-001-5.1.pdf.

RELIABILITY | RESILIENCE | SECURITY

Requested information
require stability and steady state analyses, respectively, to be performed for certain traditional extreme
events, but does not expressly require them for extreme heat and cold conditions.
Extreme weather-related events that have spanned the continent in recent years demonstrate the
challenges associated with planning for extreme heat and cold weather events, particularly those events
that affect a wide area or that occur during periods when the Bulk-Power System (BPS) must meet
unexpected high demand. Extreme heat and cold weather events have occurred with greater frequency
in recent years, and are projected to occur with even greater frequency in the future. At the same time,
the changing resource mix has resulted in a grid that is increasingly more susceptible to the impacts of
extreme heat and cold weather events.
Recent extreme weather events have shown the risk that such events can pose to the reliable operation
of the BPS, and have highlighted the high risk to life and extreme economic impacts that can result from
unplanned load shed during such conditions. Long-term transmission planning, along with other
measures, can play an important role in identifying and helping to minimize these risks.
Accordingly, this project will revise the NERC transmission planning Reliability Standards, consistent
with FERC Order No. 896, 2 to address the study of extreme heat and cold conditions. The impact of
concurrent failures of BPS generation and transmission equipment and the potential for cascading
outages that may be caused by extreme heat and cold weather events should be studied and corrective
actions should be identified and implemented.
These standard(s) should use benchmark extreme heat and cold weather events for the required
studies, and require the development of planning cases with appropriate sensitivities over a wide-area.
The standard should also require the identification and implementation of corrective actions where
system performance requirements are not met, including appropriate coordination and communication
of studies.
Purpose or Goal (How does this proposed project provide the reliability-related benefit described
above?):
Consistent with FERC Order No. 896, this purpose of this project is to address the reliability gap
pertaining to the consideration of extreme heat and cold weather events that exist in current
transmission planning standards (e.g., NERC Reliability Standard TPL-001-5.1 – Transmission System
Planning Performance Requirements).
In Order No. 896, NERC was directed to develop a new or modified Reliability Standard (“Standard”)
that requires the following: (1) the development of benchmark planning cases based on information
such as major prior extreme heat and cold weather events and/or future meteorological projections; (2)
planning for extreme heat and cold weather events using steady state and transient stability analyses
expanded to cover a range of extreme weather scenarios, including expected availability of the resource
mix during extreme heat and cold weather conditions, and including the broad area impacts of extreme

Order No. 896, Transmission System Planning Performance Requirements for Extreme Weather, 183 FERC ¶ 61,191 (2023), available at
https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20230615-3100&optimized=false.
2

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

2

Requested information
heat and cold weather; and (3) the development of corrective action plans that mitigate specified
instances where performance requirements during extreme heat and cold weather events are not met.
Project Scope (Define the parameters of the proposed project):
The scope of the proposed project is to develop a new transmission planning Standard, or modify an
existing Standard, to address the directives from FERC Order No. 896 pertaining to the study of extreme
heat and cold events. New or revised definitions may be required. This project may also need to revise
Standard MOD-032-1 – Data for Power System Modeling and Analysis 3 for data sharing.
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 4 which 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):
The drafting team is responsible for the development of new Standard or the revision of Standard TPL001-5.1 that shall achieve the actions listed below related to addressing concerns pertaining to
transmission system planning for extreme heat and cold weather events outlined in the Order that
impact the Reliable Operation of the Bulk-Power System.
The technical justification of the reliability-related benefits of developing a new Standard, modified
Standard, or industry definition were addressed in the NOPR 5 and Order. The following actions have
been listed in a sequence consistent with the directives in the Order.
A. Develop New or Modified Standard
Develop a new or modified Standard 6 to require the following: 7
1. Development of benchmark planning cases based on major prior extreme heat and cold weather
events and/or meteorological projections;
2. Planning for extreme heat and cold weather events using steady state and transient stability
analyses expanded to cover a range of extreme weather scenarios including the expected
resource mix's availability during extreme heat and cold weather conditions, and including the
wide-area impacts of extreme heat and cold weather; and

See MOD-032-1 at https://www.nerc.com/pa/Stand/Reliability%20Standards/MOD-032-1.pdf.
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.
5 See Docket RM22-10-000, NOPR 179 FERC ¶ 61,195, document number 2022-13471 at
https://www.federalregister.gov/documents/2022/06/27/2022-13471/transmission-system-planning-performance-requirements-forextreme-weather.
6 Order at P25.
7 Order at P27.
3
4

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

3

Requested information
3. Development of corrective action plans that mitigate specified instances where performance
requirements for extreme heat and cold weather events are not met. 8
Also, identify the responsible entities for developing benchmark planning cases and conducting widearea studies.
B. Develop Benchmark Events and Planning Cases Based on Major Prior Extreme Heat and Cold
Weather Events and/or Meteorological Projections
The drafting team must consider approaches that would provide a uniform framework for developing
benchmark events while still recognizing regional differences. For example, consider defining
benchmark events around:
•

a projected frequency (e.g., 1-in-50-year event); or

•

a probability distribution (95th percentile event).

Although the NOPR did not specify how these benchmark events should be developed, the NOPR
provided two examples: (1) the drafting team could develop the benchmark event or events during the
standard development process; or (2) the drafting team could include in the new or modified Standard a
framework establishing a common design basis for the development of benchmark events. In
developing a new of modified Standard, responsible entities are to be required to:[57]
1. Develop extreme heat and cold weather benchmark events; 9
2. Develop benchmark planning cases based on identified benchmark events; and
3. Describe/define the types of heat and cold scenarios/events that responsible entities must
study. 10
For instance, a benchmark event could be constructed based on data from a major prior extreme heat
or cold event, with adjustments if necessary to account for the fact that future meteorological
projections may estimate that similar events in the future are likely to be more extreme. 11
The drafting must consider the examples of approaches for defining benchmark events identified in the
NOPR (e.g., the use of projected frequency or probability distribution). 12
The drafting must ensure that benchmark events that all responsible entities likely to be impacted by
the same extreme weather events use consistent benchmark events. Doing so is important to ensuring
that neighboring planning regions are assuming similar weather conditions and are able to coordinate

NOPR, 179 FERC ¶ 61,195 at P 51.
Benchmark events will form the basis for a planner's benchmark planning case— i.e., the base case representing system conditions under
the relevant benchmark event—that will be used to study the potential wide-area impacts of anticipated extreme heat and cold weather
events.
10 Order at P35.
11 NOPR, 179 FERC ¶ 61,195 at P47.
12 Order at P36.
8
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Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

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Requested information
their assumptions accordingly. Allowing responsible entities significant discretion to determine the
applicable meteorological conditions would not meet the objectives of the Order. 13
Extreme heat and cold benchmark events must reflect regional differences in climate and weather
patterns. 14
The drafting team may and is encouraged to engage the national labs, RTOs, NOAA, and other agencies
and organizations in developing benchmark events. 15
To provide for a common design basis for responsible entities to follow when creating benchmark
planning cases, case are to represent: 16
1. Potential weather-related contingencies (e.g., concurrent/correlated generation and
transmission outages, derates) and expected future conditions of the system such as changes in
load:
2. Transfers;
3. Generation resource mix; and
4. Impacts on generators sensitive to extreme heat or cold (due to the weather conditions
indicated in the benchmark events).
The drafting team must ensure the new or modified Standard contains appropriate mechanisms for
ensuring the benchmark event reflects up-to-date meteorological data. A mechanism to update the
benchmark event at least every five years would strike a reasonable balance between the benefits of
using the most up-to-date meteorological data and administrative the burdens of collecting and
analyzing such data. 17
C. Defining “Wide-Area”
The drafting team in developing a new or modified Standard must include that transmission planning
studies consider the wide-area impacts of extreme heat and cold weather. 18 The drafting team should
consider approaches in defining “wide-area” over a geographical area consistent with weather and
electrically, and how these two approaches correlate. 19 The drafting team must clearly describe the
process that a responsible entity must use to define the wide-area boundaries. 20

Order at P37.
Order at P38.
15 Order at P37.
16 Order at P39.
17 Order at P40.
18 Order at P41.
19 Order at P47.
20 Order at P50.
13
14

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

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D. Entities Responsible for Developing Benchmark Events and Planning Cases, and for Conducting
Transmission Planning Studies of Wide-Area Events
a. Entity Responsible for Establishing Benchmark Events
The Order directed NERC to develop requirements that address the types of extreme heat and
cold weather scenarios responsible entities are required to study, including the development of
benchmark events and benchmark planning cases.
The drafting team shall develop the new or modified Standard consistent with the approach the
Commission took in Order No. 779 (i.e., TPL-007-1 – Transmission System Planned Performance
for Geomagnetic Disturbance Events). Also, define mechanisms to periodically update extreme
heat and cold weather benchmark events. 21
The drafting team may use an existing functional entity or a group of functional entities (e.g., a
group of planning coordinators) to designate the tasks of developing benchmark planning cases
and conducting wide-area studies. 22
b. Entities Responsible for Development of Planning Cases and Conducting Transmission
Planning Studies of Wide-Area Events
The drafting team is to (1) designate the responsible entities responsible for developing
benchmark planning cases, and (2) specify which responsible entities have an obligation to
conduct wide-area studies under the new or modified Standard. 23
The drafting team may designate the tasks of developing benchmark planning cases and
conducting wide-area studies to an existing functional entity or a group of functional entities
(e.g., a group of planning coordinators). If needed, the drafting team may propose to establish a
new functional entity registration to undertake these tasks by working with NERC registration
and legal staffs. The drafting team, if considering such an approach, will need to consider that a
new functional registration will require a modification to the NERC Rules of Procedure, which
can take additional time to complete. 24
E. Coordination Among Registered Entities and Sharing of Data and Study
In determining the responsible entities that will be developing benchmark planning cases and
conducting wide-area studies, the drafting team must ensure there is a mechanism is place to ensure
the sharing of data and studies. For example, it is possible that the selected responsible entities under
the new or modified Standard will not be able to request and receive needed data pursuant to MOD–
032–1, absent modification to that Standard. 25
The drafting team must require system information and study results sharing and coordination among
planning coordinators and transmission planners with transmission operators, transmission owners, and
generator owners for extreme heat and cold weather events. 26
The drafting team must address wide-area coordination among giving due consideration to relevant
factors identified by commenters in the Order and NOPR 27,28 At a minimum, the drafting team must
require responsible entities to share the results of their wide-area studies with other registered entities

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

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Requested information
consistent with TPL-00-1-5.1 (e.g., transmission operators, transmission owners, and generator owners
that have a reliability related need for the studies). 29
F. Concurrent/Correlated Generator and Transmission Outages
The drafting team must require the study of concurrent/correlated generator and transmission outages
due to extreme heat and cold events in benchmark events as described in more detail below. Previous
extreme weather events have demonstrated that there is a high correlation between generator outages
and cold temperatures, indicating that as temperatures decrease, unplanned generator outages and
derates increase. Because of this correlation, it is necessary that responsible entities evaluate the risk of
correlated or concurrent outages and derates of all types of generation resources and transmission
facilities as a result of extreme heat and cold events. Some generators may be unavailable under
extreme heat or cold conditions and thus their potential outages must be considered in extreme heat
and cold weather planning scenarios. The drafting team may strike a balance between allowing
responsible entities discretion to ensure the study incorporates their operating experience and the need
to create a robust framework that ensures extreme heat and cold events are adequately studied. 30
G. Conduct Transmission System Planning Studies for Extreme Heat and Cold Weather Events
1. Steady State and Transient Stability Analyses
In a steady state analysis, the system components are modeled as either in-service or out-ofservice and the result is a single point-in-time snapshot of the system in a state of operating
equilibrium. A transient stability (dynamic) analysis examines the system from the start to the
end of a disturbance to determine if the system regains a state of operating equilibrium.
Performing both analyses ensures that the system has been thoroughly assessed for instability,
uncontrolled separation, and cascading failures in both the steady state and the transient
stability realms.
The drafting team must require that responsible entities:
1. Perform both steady state and transient stability (dynamic) analyses in the extreme heat
and cold weather planning studies (in the long-term planning horizon 31);

Order at P59. See also Order No. 779 at https://www.federalregister.gov/documents/2016/09/30/2016-23441/reliability-standard-fortransmission-system-planned-performance-for-geomagnetic-disturbance-events.
22 Order at P62.
23 Order at P60.
24 Order at P62.
25 Order at P73.
26 Order at P65.
27 See Appendix A, P81 and P82 for additional information.
28 See Appendix B, P57, P64, and P70.
29 Order at P77.
30 Order at P88 through P91.
31 Order at P95.
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Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

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Requested information
2. Define a set of contingencies that responsible entities will be required to consider when
conducting wide-area studies of extreme heat and cold weather events under the new or
modified Standard;
3. Develop specific criteria for determining which outages should be considered in the
benchmark planning case; and
4. Model demand load response in their extreme weather event planning area. 32
2. Sensitivity Analysis
Sensitivity analyses help a transmission planner to determine if the results of the base case are
sensitive to changes in the inputs. The use of sensitivity analyses is particularly necessary when
studying extreme heat and cold events because some of the assumptions made when
developing a base case may change if temperatures change. For example, during extreme cold
events, load may increase as temperatures decrease, while a decrease in temperature may
result in a decrease in generation. 33
In developing sensitivities the drafting must:
1. Require the use of sensitivity cases to demonstrate the impact of changes to the
assumptions used in the benchmark planning case; and
2. Establish a baseline set of sensitivities for the new or modified Standard. FERC stated that
while it would not require the inclusion of any specific sensitivity in Order No. 896, NERC
should consider including conditions that vary with temperature such as load,
generation, and system transfers. 34
3. Modifications to the Traditional Planning Approach
The drafting team must require the use of planning methods that ensure adequate consideration
of the broad characteristics of extreme heat and cold weather conditions that also address:
1. Whether probabilistic elements can be incorporated into the new or modified Standard
and implemented presently by responsible entities, and
2. Identify any probabilistic planning methods that would improve upon existing planning
practices, but are infeasible to include in a new or modified Standard at this time. 35
H. Implement a Corrective Action Plan if Performance Standards Are Not Met
The Order specifies that NERC must develop standards that require Corrective Action Plans that include
mitigation for any instances where performance requirements for extreme heat and cold events are not

Order at P111 through P116.
Order at P124 and also at P126.
34 Order at P124.
35 Order at P134, P138, and P158.
32
33

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

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met; therefore, the drafting must require the development of extreme weather corrective action plans
that:
1. Identify specified instances when performance standards are not met;
2. Require certain processes to facilitate interaction and coordination with applicable regulatory
authorities or governing bodies responsible for retail electric service as appropriate in
implementing a corrective action plan;
3. Require mitigation for specified instances where performance requirements for extreme heat
and cold events are not met (i.e., when certain studies conducted under the Standard show that
an extreme heat or cold event would result in cascading outages, uncontrolled separation, or
instability);
4. Determine whether corrective action plans should be required for single or multiple sensitivity
cases;
5. Determine whether corrective action plans should be developed if a contingency event that is
not already included in benchmark planning case would result in cascading outages,
uncontrolled separation, or instability;
6. Establish required study contingencies and baseline sensitivities for which a corrective action
plan is required; and
7. Require that responsible entities share their corrective action plans with, and solicit feedback
from, applicable regulatory authorities or governing bodies responsible for retail electric service
issues. 36
I. Other Extreme Weather-Related Events and Issues
Reliability Standard Implementation Timeline
NERC must submit a responsive Reliability Standard to FERC by December 23, 2024.
The proposed implementation timeline for a new or modified Reliability Standard must have an
implementation beginning no later than 12 months after the effective date of a Commission order
approving the proposed new or modified Reliability Standard. 37
The drafting team in developing the standard has the discretion to develop a phased-in implementation
timeline for the different requirements of the proposed Reliability Standard (i.e., developing benchmark
cases, conducting studies, developing corrective action plans, etc.). However, this phased-in
implementation must begin within 12 months of the effective date of a Commission order approving
the proposed Reliability Standard and must include a clear deadline for implementation of all
requirements. 38
Other
There is a concern that there is limited modeling of protection systems in dynamic assessments
currently, and any dynamic simulation of extreme events would require significant modeling of
protection systems to provide for convergence of the numerical simulation. The drafting team in
developing the planning requirements for extreme heat and cold weather must take into account any

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

9

Requested information
deficiencies in dynamic modeling of protection systems. The dynamics databases used for transient
stability simulations by various interconnections typically do not include comprehensive dynamic
models of relays installed in the interconnection. The drafting team should consider wide-area
applications by various interconnections that may not typically include comprehensive dynamic models
of relays installed in the interconnection. 39
The drafting team should consider the cost impacts to responsible entities.
Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated
with the proposed project):
The cost impact is unknown and will be considered during drafting team meetings. However, The SAR
proposes to either create a new Standard or modify an existing Standard(s) that would require
responsible entities to create Corrective Action Plans to address risks related to transmission system
planning performance for extreme weather directed in the Order. The costs associated are anticipated
to be comparable to those associated with a responsible entity’s performance of TPL-007-1 –
Transmission System Planned Performance for Geomagnetic Disturbance Events.
Please describe any unique characteristics of the BES facilities that may be impacted by this proposed
standard development project (e.g., Dispersed Generation Resources):
BES facilities may be uniquely impacted by the results of improved studies that incorporate enhanced
extreme heat and cold weather scenarios and sensitivity analyses performed by the transmission
planners. Mitigating and corrective actions may require transmission system topology changes,
including but not limited to re-evaluating load shedding plans as a safety net in response to high
demand in extreme heat and cold weather over a wide-area. For example, if studies reveal thermal
violations that could be anticipated during extreme weather, transmission facilities may need to be
upgraded.
Generation facilities may be impacted by having to change the way concurrent or coincident generator
outages are managed and planned to reduce the likelihood of not meeting high demands over a widearea. For example, if multiple generators are disrupted due to pipeline issues and don’t have dual fuel
capability.
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):
The development of a new or modified Standard should consider drafting team individuals from the
following functional entities: Balancing Authority, Generator Owner, Planning Coordinator, Reliability
Coordinator, Transmission Owner, and Transmission Planner.

Order at P152 through P158, and P165.
Order at P188.
38 Order at P193.
39 Order at P68 and P74.
36
37

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

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Requested information
Do you know of any consensus building activities 40 in connection with this SAR? If so, please provide any
recommendations or findings resulting from the consensus building activity.
In Order No. 896, FERC highlighted that industry experts agreed that extreme weather events are likely
to become more severe and frequent in the future and there is a need to address them in the long-term
planning horizon.
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)?
TPL-001-5.1a and MOD-032-1.
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.
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.

Enter
(yes/no)
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.

40

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

11

Market Interface Principles
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.

Yes
Yes
Yes

Identified Existing or Potential Regional or Interconnection Variances
Region(s)/
Explanation
Interconnection
e.g., NPCC
No needed Regional or Interconnection variances were identified. The Order did
acknowledge that the drafting team consider approaches that would provide a
uniform framework for developing benchmark events while still recognizing regional
differences in climate and weather patterns, among other considerations; therefore,
the use of region is considered to be the common geographical understanding and
not NERC Regional Entity footprints. The Commission disagreed that Regional Entities
and reliability coordinators should not lead the development of benchmark events
and that the drafting team should. 41

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

41

Date

Owner

Change Tracking

1

June 3, 2013

Revised

1

August 29, 2014

Standards Information Staff

Updated template

2

January 18, 2017

Standards Information Staff

Revised

Order at P58.

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

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2

June 28, 2017

Standards Information Staff

Updated template

3

February 22, 2019

Standards Information Staff

Added instructions to submit via Help
Desk

4

February 25, 2020

Standards Information Staff

Updated template footer

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

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Appendix A
Excerpts from NOPR, 179 FERC ¶ 61,195
P51. February 2011 Southwest Cold Weather Event and January 2014 Polar Vortex Cold Weather Event
81. While balancing authorities and other entities must share system information and study results with
their transmission and planning coordinator pursuant to Reliability Standards MOD-032-1 and TPL-001-5.1
as described above, there is no required sharing of such information—or required coordination—among
planning coordinators and transmission planners with transmission operators, transmission owners, and
generator owners, thus limiting the benefits of additional modeling. Sharing system information and study
results and enhancing coordination among these entities for extreme heat and cold weather events could
result in more representative planning models by better:
(1) integrating and including operations concerns ( e.g., lessons learned from past issues including
corrective actions and projected outcomes from these actions, evolving issues concerning extreme
heat/cold) in planning models; and
(2) conveying reliability concerns from planning studies ( e.g., potential widespread cascading,
islanding, significant loss of load, blackout, etc.) as they pertain to extreme heat or cold.
82. Therefore, as part of its revisions, NERC should require system information and study results sharing,
and coordination among planning coordinators and transmission planners with transmission operators,
transmission owners, and generator owners for extreme heat and cold weather events. To better
understand the benefits of the suggested actions, we are inviting comments on:
(1) the parameters and timing of coordination and sharing;
(2) specific protocols that may need to be established for efficient coordination practices; and
(3) potential impediments to the proposed coordination efforts.

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

14

Appendix B
Excerpts from Order No. 896
57. Environmental Defense Fund (EDF), Tri-State, and Eversource Energy Service Company (Eversource)
propose that reliability coordinators should have the responsibility to perform wide-area planning and
coordination in collaboration with other impacted reliability coordinators
64. there is no required sharing of such information related to extreme heat or cold weather events—or
required coordination—among planning coordinators and transmission planners with transmission
operators, transmission owners, and generator owners. Sharing system information and study results and
enhancing coordination among these entities for extreme heat and cold weather events could result in
more representative planning models by better integrating and including operations concerns ( e.g.,
lessons learned from past issues including corrective actions and projected outcomes from these actions,
evolving issues concerning extreme heat/cold) in planning models; and conveying reliability concerns
from planning studies ( e.g., potential widespread cascading, islanding, significant loss of load, blackout,
etc.) as they pertain to extreme heat or cold. 42
70. Tri-State suggests that the balancing authority should address the results of the studies and how they
should communicate those results among the transmission planners. Tri-State also asserts that the
balancing authority is responsible for resource adequacy and should communicate resource needs for the
area with the responsible transmission planners who can evaluate system needs and “provide access to
remove” resource needs.

42

NOPR at P81.

Standard Authorization Request – Transmission System Planning Performance Requirements for Extreme Weather

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Limited Disclosure

Agenda Item 11
Standards Committee
December 13, 2023
Project 2023-07 Transmission System Planning Performance
Requirements for Extreme Weather
Action

Approve the following waiver of provisions of the Standard Processes Manual (SPM) for Project
2023-07 Transmission System Planning Performance Requirements for Extreme Weather:
•

Initial formal comment and ballot period reduced from 45 days to as few as 25 calendar
days, with ballot pools formed in the first 10 days of the comment period. (Sections 4.9
and 4.12)

•

Additional formal comment and ballot period(s) reduced from 45 days to as few as 15
calendar days, with ballot(s) conducted during the last five days of the comment period.
(Sections 4.9 and 4.12)

•

Final ballot period reduced from 10 days to as few as five calendar days. (Section 4.9)

Background

Section 16.0 of the SPM allows the Standards Committee to waive any provision in the SPM for
good cause, including for the following reasons:
Where the Standards Committee determines that a modification to a proposed
Reliability Standard or its Requirement(s), a modification to a defined term, a
modification to an Interpretation, or a modification to a Variance has already been
vetted by the industry through the standards development process or is so insubstantial
that developing the modification through the processes contained in this manual will
add significant time delay.
On June 15, 2023, FERC issued FERC Order 896, directing NERC to develop a new or modified
Reliability Standard to address a need for long-term planning requirement(s) for extreme heat
and cold weather events. Specifically, FERC directed NERC to develop modifications to
Reliability Standard TPL-001-5.1 or a new Reliability Standard, to require the following: (1)
development of benchmark planning cases based on major prior extreme heat and cold
weather events and/or meteorological projections; (2) planning for extreme heat and cold
weather events using steady state and transient stability analyses expanded to cover a range of
extreme weather scenarios including the expected resource mix's availability during extreme
heat and cold weather conditions, and including the wide-area impacts of extreme heat and
cold weather; and (3) development of corrective action plans that mitigate any instances where
performance requirements for extreme heat and cold weather events are not met. In addition
to these directives, FERC directed NERC to modify an existing or create a new Reliability
Standard by December 2024.
Summary

Given the stage of the directed due date of December 2024, the drafting team needs flexibility
to condense the ballot and comment periods necessary to meet this due date while following
the NERC processes therefore Project 2023-07 DT leadership and NERC staff recommend that
the SC shorten the initial formal comment and ballot period from 45 days to as few as 25 days
and any additional formal comment and ballot period(s) from 45 days to as few as 15 days. In
Limited Disclosure

Limited Disclosure

addition, Project 2023-07 DT leadership and NERC staff recommend shortening the final ballot
from 10 days to 5 days.

Limited Disclosure

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

TPL-008-1 is posted for a 45-day formal comment and initial ballot.
Completed Actions

Date

Standards Committee approved Standard Authorization Request (SAR)
for posting

July 19, 2023

SAR posted for comment

August 8 – September 27,
2023

Anticipated Actions

Date

45-day formal comment period with initial ballot

March 20 – May 3, 2024

45-day formal comment period with additional ballot

June 2024

45-day formal comment period with additional ballot

September 2024

10-day final ballot

November 2024

Board adoption

December 2024

Draft 1 of TPL-008-1
March 2024

Page 1 of 20

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

New or Modified Term(s) Used in NERC Reliability Standards

This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):

Extreme Temperature Assessment – Documented evaluation of future Transmission System
performance for extreme heat and extreme cold temperature benchmark events.

Draft 1 of TPL-008-1
March 2024

Page 2 of 20

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements for
Extreme Temperature Events

2.

Number:

TPL-008-1

3.

Purpose:

Establish requirements for Transmission system planning performance
for extreme heat and extreme cold temperature events

4.

Applicability:
4.1. Functional Entities:
4.1.1. Transmission Planner
4.1.2. Planning Coordinator

5.

Effective Date: See Implementation Plan for Project 2023-07.

Draft 1 of TPL-008-1
March 2024

Page 3 of 20

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

B. Requirements and Measures
R1. Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
determine and identify each entity’s individual and joint responsibilities for
performing the studies needed to complete the Extreme Temperature Assessment.
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
M1. Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
provide documentation of each entity’s individual and joint responsibilities, such as
meeting minutes, agreements, copies of procedures or protocols in effect between
entities or between departments of a vertically integrated system, or email
correspondence that identifies an agreement has been reached on individual and joint
responsibilities for performing the studies needed to complete the Extreme
Temperature Assessment.
R2. Each responsible entity, as identified in Requirement R1, shall select one extreme heat
benchmark event and one extreme cold benchmark event, from the approved
benchmark library maintained by the Electric Reliability Organization (ERO), for
performing the Extreme Temperature Assessment. [Violation Risk Factor: High] [Time
Horizon: Long-term Planning]
M2. Each responsible entity, as identified in Requirement R1, shall have evidence in either
electronic or hard copy format of its selected extreme heat benchmark event and
extreme cold benchmark event for performing the Extreme Temperature Assessment.
R3. Each Planning Coordinator shall develop and implement a process for coordinating the
development of benchmark planning cases among impacted Planning Coordinator(s),
Transmission Planner(s), and other designated study entities based on the selected
benchmark events as identified in Requirement R2. This process shall: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
3.1. Define the planning study area boundary based on the selected benchmark
events.
3.2. Modify the benchmark planning cases to include seasonal and temperature
dependent adjustment for Load, generation, Transmission, and transfers which
represents the selected benchmark events.
M3. Each Planning Coordinator shall provide dated evidence of a process for coordinating
the development of benchmark planning cases among impacted Planning
Coordinators, and Transmission Planner(s) as specified in Requirement R3. Acceptable
evidence may include, but is not limited to, the following dated documentation
(electronic or hardcopy format): records defining the planning study area boundary
based on the selected benchmark events and modifications to the benchmark
planning cases that include seasonal and temperature dependent adjustment for
Load, generation, Transmission, and transfers which represent the selected
benchmark events.
Draft 1 of TPL-008-1
March 2024

Page 4 of 20

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R4. Each responsible entity, as identified in Requirement R1, shall develop and maintain
System models within its planning area for performing the Extreme Temperature
Assessment. The System models shall use data consistent with that provided in
accordance with the MOD-032 standard, supplemented by other sources as needed,
and shall represent projected System conditions based on the selected benchmark
events as identified in Requirement R2. [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
M4. Each responsible entity, as identified in Requirement R1, shall have evidence in either
electronic or hard copy format that it developed and maintained System models of the
responsible entity’s planning area for performing the Extreme Temperature
Assessment.
R5. Each responsible entity, as identified in Requirement R1, shall have criteria for
acceptable System steady state voltage limits and post-Contingency voltage deviations
for performing the Extreme Temperature Assessment in accordance with Requirement
R3. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
M5. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
such as electronic or hard copies of the documentation specifying the criteria for
acceptable System steady state voltage limits and post-Contingency voltage deviations
for performing the Extreme Temperature Assessment in accordance with Requirement
R5.
R6. Each responsible entity, as identified in Requirement R1, shall define and document
the criteria or methodology used in the Extreme Temperature Assessment analysis to
identify instability, uncontrolled separation, or Cascading. [Violation Risk Factor: High]
[Time Horizon: Long-term Planning]
M6. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
such as electronic or hard copy documentation of the defined and documented
criteria or methodology used to identify instability, uncontrolled separation, or
Cascading used in the Extreme Temperature Assessment analysis in accordance with
Requirement R6.
R7. Each responsible entity, as identified in Requirement R1, shall identify Contingencies
used in performing the Extreme Temperature Assessment for each of the event
categories in Table 1 that are expected to produce more severe System impacts within
its planning area. The rationale for those Contingencies selected for evaluation shall
be available as supporting information. [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
M7. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
such as electronic or hard copy documentation that it has identified Contingencies for
performing the Extreme Temperature Assessment for each of the event categories in
Table 1 that are expected to produce more severe System impacts within its planning
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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

area and the supporting rationale, in accordance with Requirement R7, such as
electronic or hard copies of documents identifying the Contingencies with supporting
rationale.
R8. Each responsible entity, as identified in Requirement R1, shall complete an Extreme
Temperature Assessment of the Long-Term Transmission Planning Horizon at least
once every five calendar years, using the benchmark planning cases and the System
models identified in Requirement R3 and R4, and the Contingencies identified in
Requirement R7 for each of the event categories in Table 1, and document
assumptions and results of the steady state and stability analyses. The Extreme
Temperature Assessment shall include the following. [Violation Risk Factor: High]
[Time Horizon: Long-term Planning]
8.1. Assessment of the benchmark planning cases developed under Requirement R4,
for one of the years in the Long-Term Transmission Planning Horizon. The
rationale for the year selected for evaluation shall be available as supporting
information.
8.2. Sensitivity analysis to demonstrate the impact of changes to the basic
assumptions used in the model. To accomplish this, the sensitivity analysis in the
Extreme Temperature Assessment shall include, at a minimum, changes to one
of the following conditions:
•

Generation;

•

Real and reactive forecasted Load; or

•

Transfers

M8. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
that it performed an Extreme Temperature Assessment, such as electronic or hard
copies of the assessment, meeting all the requirements in Requirement R8.
R9. Each responsible entity, as identified in Requirement R1, shall develop a Corrective
Action Plan(s) (CAPs) when the benchmark planning case study results indicate the
System is unable to meet performance requirements for Table 1 P0 or P1
Contingencies. The responsible entities shall share their CAPs with, and solicit
feedback from, applicable regulatory authorities or governing bodies responsible for
retail electric service issues. In addition, where Load shed is allowed as an element of
a CAP for the Table 1 P1 Contingency, the responsible entity shall document the
alternative(s) considered, as mentioned in Requirement R10, and notify the applicable
regulatory authorities or governing bodies responsible for retail electric service issues.
Revisions to the CAP(s) are allowed in subsequent Extreme Temperature Assessments,
but the planned System shall continue to meet the performance requirements.
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

M9. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
such as electronic or hard copy documentation of a CAP, including any revision
history, when the benchmark planning case study results indicate the System is unable
to meet performance requirements for the Table 1 P0 or P1 Contingencies in
accordance with Requirement R9.
R10. Each responsible entity, as identified in Requirement R1, shall evaluate and document
possible actions designed to reduce the likelihood or mitigate the consequences and
adverse impacts when the benchmark planning case study results indicate the System
could result in instability, uncontrolled separation, or Cascading for the Table 1 P2, P4,
P5, and P7 Contingencies. [Violation Risk Factor: Lower] [Time Horizon: Long-term
Planning]
M10. Each responsible entity, as identified in Requirement R1, shall provide the dated
evidence that it evaluated and documented possible actions designed to reduce the
likelihood or mitigate the consequences and adverse impacts when the benchmark
planning case study results indicate the System could result in instability, uncontrolled
separation, or Cascading for the Table 1 P2, P4, P5, and P7 Contingencies in
accordance with Requirement R10, such as electronic or hard copies of the
assessment detailing such actions.
R11. Each responsible entity, as identified in Requirement R1, shall provide its Extreme
Temperature Assessment results within 60 calendar days of a request to any
functional entity that has a reliability related need and submits a written request for
the information. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M11. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as email notices, documentation of updated web pages, postal receipts showing
recipient; or a demonstration of a public posting that it provided its Extreme
Temperature Assessment to any functional entity who has a reliability need within 60
calendar days of a written request.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) 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 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 responsible entity shall retain evidence of compliance with each
requirement in this standard for five calendar years or one complete
Extreme Temperature Assessment cycle, whichever is longer.

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” 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.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1: Contingencies and Performance Criteria
Event
Facility Voltage Level of
Contingency

Steady State
Performance Criteria

Stability Performance
Criteria
Corrective Action Plan
Required

Non-Consequential Load
Loss Allowed

Draft 1 of TPL-008-1
March 2024

P0

P1

P2

P4

P5

P7

Applicable to:
• BES level 200 kV and above
• Any common structure that includes a Facility 200kV and above
Reference Voltages:
• Non-generator step up transformer outage events, the reference voltage applies to the low-side winding.
• Generator and generator step-up transformer outage events, the reference voltage applies to the BES connected voltage (highside of the step-up transformer).
Evaluation for uncontrolled separation or Cascading, as defined in
• Applicable Facility Ratings • Applicable Facility ratings
Requirement R6.
shall not be exceeded.
shall not be exceeded
• System steady state
• System steady state
voltages shall be within
voltages shall be within
acceptable limits as
acceptable limits as defined
defined in Requirement
in Requirement R5.
R5.
Initialization without
Instability, uncontrolled
Evaluation for instability, uncontrolled separation, or Cascading, as
oscillation
separation, or Cascading, as
defined in Requirement R6.
defined in Requirement R6,
shall not occur.
Yes (See Requirement R9)
Yes (See Requirement R9)
No (See Requirement R10)

No (See Requirement R9)

Yes (See Requirement R9)

Yes

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1: Contingencies and Performance Criteria
Category
P0
No Contingency

P1
Single Contingency

P2
Single Contingency

Draft 1 of TPL-008-1
March 2024

Initial Condition
Normal System

Normal System

Normal System

Event

Fault Type 1

None

N/A

Loss of one of the following:
1. Generator
2. Transmission Circuit
3. Transformer
4. Shunt Device2

3Ø

5. Single Pole of a DC line

SLG

1. Opening of a line section w/o a fault 3

N/A

2. Bus Section Fault

SLG

3. Internal Breaker Fault4
(non-Bus-tie Breaker)

SLG

4. Internal Breaker Fault (Bus-tie Breaker)4

SLG

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1: Contingencies and Performance Criteria
Category

P4
Multiple Contingency
(Fault plus stuck
breaker10)

Initial Condition

Normal System

Event
Loss of multiple elements caused by a stuck breaker5(non-Bus-tie
Breaker) attempting to clear a Fault on one of the following:
1. Generator
2. Transmission Circuit
3. Transformer
4. Shunt Device2
5. Bus Section
6. Loss of multiple elements caused by a stuck breaker5 (Bus-tie
Breaker) attempting to clear a Fault on the associated bus

P5
Multiple Contingency
(Fault plus nonredundant component of
a Protection System
failure to operate)
P7
Multiple Contingency
(Common Structure)

Draft 1 of TPL-008-1
March 2024

Fault Type 1

SLG

SLG

Normal System

Delayed Fault Clearing due to the failure of a non-redundant component of a Protection
System7 protecting the Faulted element to operate as designed, for one of the following:
1. Generator
2. Transmission Circuit
3. Transformer
4. Shunt Device2
5. Bus Section

Normal System

The loss of:
1. Any two adjacent (vertically or horizontally) circuits on common
structure 6
2. Loss of a bipolar DC line

SLG

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)
1. Unless specified otherwise, simulate Normal Clearing of faults. Single line to ground (SLG) or three-phase (3Ø) are the fault types that must be evaluated in
Stability simulations for the event described. A 3Ø or a double line to ground fault study indicating the criteria are being met is sufficient evidence that a
SLG condition would also meet the criteria.
2. Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
3. Opening one end of a line section without a fault on a normally networked Transmission circuit such that the line is possibly serving Load radial from a
single source point.
4. An internal breaker fault means a breaker failing internally, thus creating a System fault which must be cleared by protection on both sides of the breaker.
5. A stuck breaker means that for a gang-operated breaker, all three phases of the breaker have remained closed. For an independent pole operated (IPO) or
an independent pole tripping (IPT) breaker, only one pole is assumed to remain closed. A stuck breaker results in Delayed Fault Clearing.
6. Excludes circuits that share a common structure (Planning event P7) for one mile or less.
7. For purposes of this standard, non-redundant components of a Protection System to consider are as follows:
a. A single protective relay which responds to electrical quantities, without an alternative (which may or may not respond to electrical quantities) that
provides comparable Normal Clearing times;
b. A single communications system associated with protective functions, necessary for correct operation of a communication-aided protection scheme
required for Normal Clearing (an exception is a single communications system that is both monitored and reported at a Control Center);
c. A single station dc supply associated with protective functions required for Normal Clearing (an exception is a single station dc supply that is both
monitored and reported at a Control Center for both low voltage and open circuit);

d. A single control circuitry (including auxiliary relays and lockout relays) associated with protective functions, from the dc supply through and including
the trip coil(s) of the circuit breakers or other interrupting devices, required for Normal Clearing (the trip coil may be excluded if it is both monitored
and reported at a Control Center).

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels
Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R1.

N/A

N/A

N/A

The Planning Coordinator, in
conjunction with its
Transmission Planner(s), failed
to determine and identify
individual and joint
responsibilities for performing
the required studies for the
Extreme Temperature
Assessment.

R2.

N/A

N/A

The responsible entity did not
select an extreme heat
benchmark event or extreme
cold benchmark event from
the ERO approved benchmark
library.

The responsible entity did not
select an extreme heat
benchmark event and extreme
cold benchmark event from
the ERO approved benchmark
library.

R3.

N/A

N/A

N/A

The Planning Coordinator did
not develop or implement a
process for coordinating the
development of benchmark
planning cases among
impacted Planning
Coordinator(s), Transmission
Planner(s), and other
designated study entities.
OR

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R#

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL
The Planning Coordinator
developed and implemented a
process for coordinating the
development of benchmark
planning cases among
impacted Planning
Coordinator(s), Transmission
Planner(s), and other
designated study entities, but
this process did not define the
planning study area boundary
based off the selected
benchmark events.
OR
The Planning Coordinator
developed and implemented a
process for coordinating the
development of benchmark
planning cases among
impacted Planning
Coordinator(s), Transmission
Planner(s), and other
designated study entities, but
this process did not modify the
benchmark planning cases to
include seasonal and
temperature dependent
adjustments load, generation,
Transmission, and transfers.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels

R#

R4.

Lower VSL

N/A

Moderate VSL

N/A

High VSL

N/A

Severe VSL

The responsible entity did not
develop or maintain System
models of the responsible
entity’s planning area for
performing Extreme
Temperature Assessment.
OR
The responsible entity
developed and maintained
System models for performing
Extreme Temperature
Assessment, but the System
model did not use data
consistent with that provided
in accordance with the MOD032 standard supplemented by
other sources as needed.

R5.

N/A

Draft 1 of TPL-008-1
March 2024

N/A

N/A

The responsible entity, as
determined in Requirement
R1, did not have criteria for
acceptable System steady
state voltage limits and postContingency voltage
deviations for performing
Extreme Temperature
Assessment.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R6.

N/A

N/A

N/A

The responsible entity failed to
define and document, the
criteria or methodology used
in the analysis to identify
System instability,
uncontrolled separation, or
Cascading.

R7.

N/A

N/A

The responsible entity, as
determined in Requirement
R1, identified Contingencies
for performing Extreme
Temperature Assessment for
each of the event categories
in Table 1 that are expected to
produce more severe System
impacts within its planning
area, but did not include the
rationale for those
Contingencies selected for
evaluation as supporting
documentation.

The responsible entity, as
determined in Requirement
R1, did not identify
Contingencies for performing
Extreme Temperature
Assessment for each of the
event categories in Table 1
that are expected to produce
more severe System impacts
within its planning area.

R8.

The responsible entity, as
determined in Requirement
R1, completed an Extreme
Temperature Assessment,
but it was completed less
than or equal to six months
late.

The responsible entity, as
determined in Requirement
R1, completed an Extreme
Temperature Assessment, but
it was completed more than
six months but less than or
equal to 12 months late.

The responsible entity, as
determined in Requirement
R1, completed an Extreme
Temperature Assessment, but
it was completed more than
12 months but less than or
equal to than 18 months late.

The responsible entity, as
determined in Requirement
R1, completed an Extreme
Temperature Assessment, but
it was more than 18 months
late.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
OR
The responsible entity, as
determined in Requirement
R1, did not complete an
Extreme Temperature
Assessment.
OR
The responsible entity, as
determined in Requirement
R1, completed an Extreme
Temperature Assessment, but
it was missing one or more of
the required elements in
Requirement R8.

R9.

N/A

N/A

The responsible entity, as
determined in Requirement
R1, developed a CAP, but
failed to solicit feedback from,
applicable regulatory
authorities or governing
bodies responsible for retail
electric service issues.

The responsible entity, as
determined in Requirement
R1, failed to develop a
Corrective Action Plan when
the benchmark planning case
study results indicate the
System is unable to meet
performance requirements for
the Table 1 P0 or P1
Contingencies.

R10.

N/A

N/A

N/A

Each responsible entity, as
determined in Requirement

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
R1, failed to evaluate and
document possible actions
designed to reduce the
likelihood or mitigate the
consequences and adverse
impacts when the benchmark
planning case study results
indicate the System could
result in instability,
uncontrolled separation, or
Cascading for the Table 1 P2,
P4, P5, and P7 Contingencies.

R11.

The responsible entity, as
determined in Requirement
R1, distributed its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 60 days but
less than or equal to 80 days
following the request.

The responsible entity, as
determined in Requirement
R1, distributed its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 80 days but
less than or equal to 100 days
following the request.

The responsible entity, as
determined in Requirement
R1, distributed its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 100 days but
less than or equal to 120 days
following the request.

The responsible entity, as
determined in Requirement
R1, distributed its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 120 days
following the request.
OR
The responsible entity, as
determined in Requirement
R1, did not distribute its
Extreme Temperature
Assessment results to
functional entities having a

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
reliability related need who
requested the information in
writing.

D. Regional Variances
None.

E. Associated Documents
•

Implementation Plan for 2023-07

•

Technical Rationale Document

•

Consideration of Issues and Directives for FERC Order 896.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Version History
Version

Date

Action

Change
Tracking

1

TBD

Addressing FERC Order 896

New Standard

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Page 20 of 20

Implementation Plan

Project 2023-07 Transmission System Planning Performance
Requirements for Extreme Weather
Applicable Standard
•

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature
Events

Requested Retirement

•

Not applicable

Prerequisite Standard

•

Not applicable

Applicable Entities

•

Planning Coordinators

•

Transmission Planners

New Terms in the NERC Glossary of Terms

•

Extreme Temperature Assessment

Background

On June 15, 2023, FERC issued a Final Rulemaking directing NERC to develop a new or modified Reliability
Standard to address the lack of a long-term planning requirement(s) for extreme heat and cold weather
events. Specifically, FERC directed NERC to develop modifications to Reliability Standard TPL-001-5.1 or
develop a new Reliability Standard that require the following: (1) development of benchmark planning cases
based on major prior extreme heat and cold weather events and/or meteorological projections; (2) planning
for extreme heat and cold weather events using steady state and transient stability analyses expanded to
cover a range of extreme weather scenarios including the expected resource mix’s availability during
extreme heat and cold weather conditions, and including the wide-area impacts of extreme heat and cold
weather; and (3) development of Corrective Action Plans that mitigate any instances where performance
requirements for extreme heat and cold weather events are not met.
Effective Date

The effective date for the proposed Reliability Standard is provided below. Where the standard drafting
team identified the need for a longer implementation period for compliance with a particular section of the
proposed Reliability Standard (e.g., an entire Requirement or a portion thereof), the additional time for
compliance with that section is specified below. These phased-in compliance dates represent the dates that

RELIABILITY | RESILIENCE | SECURITY

entities must begin to comply with that particular section of the Reliability Standard, even where the
Reliability Standard goes into effect at an earlier date.
TPL-008-1
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 twelve (12) 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 twelve
(12) months after the date the standard is adopted by the NERC Board of Trustees, or as otherwise provided
for in that jurisdiction.
Phased-In Compliance Dates

Compliance Date for TPL-008-1 Requirements R1
Entities shall be required to comply with Requirements R1 upon the effective date of Reliability Standard
TPL-008-1.
Compliance Date for TPL-008-1 Requirements R2, R3, R4, R5, R6
Entities shall not be required to comply with Requirement R2, R3, R4, R5, and R6 until thirty-six (36) months
after the effective date of Reliability Standard TPL-008-1.
Compliance Date for TPL-008-1 Requirements R7, R8, R9, R10, R11
Entities shall not be required to comply with Requirement R7, R8, R9, R10, R11 until sixty (60) months after
the effective date of Reliability Standard TPL-008-1.

Implementation Plan
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | March 2024

2

Implementation Plan
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | March 2024

3

Technical Rationale and
Justification for TPL-008-1
Project 2023-07 Transmission Planning
Performance Requirements for Extreme
Weather
March 2024

RELIABILITY | RESILIENCE | SECURITY

NERC | Report Title | Report Date
I

Table of Contents
Preface ........................................................................................................................................................................... iii
Introduction ................................................................................................................................................................... iv
Defined Terms ................................................................................................................................................................. 5
TPL-008-1 Standard ......................................................................................................................................................... 6
Requirement R1 .............................................................................................................................................................. 7
Requirement R2 .............................................................................................................................................................. 8
Requirement R3 .............................................................................................................................................................. 9
Requirement R4 ............................................................................................................................................................ 10
Requirement R5 ............................................................................................................................................................ 11
Requirement R6 ............................................................................................................................................................ 12
Requirement R7 ............................................................................................................................................................ 13
Requirement R8 ............................................................................................................................................................ 14
Requirement R9 ............................................................................................................................................................ 16
Requirement R10 .......................................................................................................................................................... 17
Requirement R11 .......................................................................................................................................................... 18

NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
ii

Preface
Electricity is a key component of the fabric of modern society and the Electric Reliability Organization (ERO) Enterprise
serves to strengthen that fabric. The vision for the ERO Enterprise, which is comprised of NERC and the six Regional
Entities, is a highly reliable, resilient, and secure North American bulk power system (BPS). Our mission is to assure
the effective and efficient reduction of risks to the reliability and security of the grid.
Reliability | Resilience | Security
Because nearly 400 million citizens in North America are counting on us
The North American BPS is made up of six Regional Entities as shown on the map and in the corresponding table
below. The multicolored area denotes overlap as some load-serving entities participate in one Regional Entity while
associated Transmission Owners/Operators participate in another.

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

Texas RE

Texas Reliability Entity

WECC

WECC

NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
iii

Introduction
This document explains the technical rationale and justification for the proposed Reliability Standard TPL-008-1. It
provides stakeholders and the ERO Enterprise with an understanding of the technology and technical requirements
in the Reliability Standard. This Technical Rationale and Justification for TPL-008-1 is not a Reliability Standard and
should not be considered mandatory and enforceable.

Background

On June 15, 2023, FERC issued FERC Order No. 896 that acknowledges the “challenges associated with planning for
extreme heat and cold weather events, particularly those that occur during periods when the Bulk-Power System
must meet unexpectedly high demand. Extreme heat and cold weather events have occurred with greater frequency
in recent years and are projected to occur with even greater frequency in the future. These events have shown that
load shed during extreme temperatures result in unacceptable risk to life and have extreme economic impact. As
such, the impact of concurrent failures of Bulk-Power System generation and transmission equipment and the
potential for cascading outages that may be caused by extreme heat and cold weather events should be studied and
corrective actions should be identified and implemented.” 1
Therefore, the Commission directed in FERC Order No. 896 to develop a new or modified Reliability Standard to
address a lack of long-term planning requirement(s) for extreme heat and cold weather events. Specifically, FERC
directed NERC to develop modifications to Reliability Standard TPL-001-5.1 or a new Reliability Standard, to require
the following: (1) development of benchmark planning cases based on major prior extreme heat and cold weather
events and/or meteorological projections; (2) planning for extreme heat and cold weather events using steady state
and transient stability analyses expanded to cover a range of extreme weather scenarios including the expected
resource mix's availability during extreme heat and cold weather conditions, and including the wide-area impacts of
extreme heat and cold weather; and (3) development of corrective action plans that mitigate any instances where
performance requirements for extreme heat and cold weather events are not met.

1

N. Am. Elec. Reliability Corp., 183 FERC ¶ 61,191 (2023) (FERC Order), Final Rule. eLibrary | File List (ferc.gov)
NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
iv

Defined Terms
The drafting team defined one term to be added to the NERC Glossary of terms to make the requirements easier to
read and understand.
Extreme Temperature Assessment
Documented evaluation of future Transmission System performance for extreme heat and extreme cold
temperature benchmark events.
The definition of Extreme Temperature Assessment was developed by the drafting team to limit wordiness
throughout the requirements.

NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
5

TPL-008-1 Standard
The FERC Order No. 896 directed NERC to submit a new Reliability Standard or modifications to Reliability Standard
TPL-001-5.1 to address the concerns pertaining to transmission system planning for extreme heat and cold weather
events that impact the Reliable Operation of the Bulk-Power System.
The drafting team developed TPL-008-1 to address the FERC directive and determined that a new Reliability
standard was the cleanest way to address all directives versus modifying TPL-001-5.1. While the TPL-008-1 standard
pulls in similar requirements, this allows industry to have one standard that focuses on extreme heat and extreme
cold weather benchmark planning analysis requirements.

NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
6

Requirement R1
Requirement R1 was drafted to allow Planning Coordinator (PC) and Transmission Planner(s) (TP) within the PC’s
footprint, to sync up regarding their individual and joint responsibilities when performing the required studies. This
will assist entities with clarity on who will complete the other respective requirements within the TPL-008-1
Reliability Standard.

NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
7

Requirement R2
Requirement R2 describes the need to select foundational weather data necessary for the creation of benchmark
planning cases. Specifically, extreme hot and cold temperatures experienced during benchmark events are assumed
to be outside the ranges used as the basis of planning cases studied under TPL-005-1.1. Since temperature levels and
associated weather conditions affect load levels, generation performance, and transfer levels, the selection of
benchmark events is critical to ensuring the Extreme Temperature Assessment appropriately evaluates probable
system conditions.
The Standard Drafting Team (SDT) determined that the extreme heat and cold temperatures selected must have a
verified statistical basis based on weather data from credible sources. However, because there are many factors to
consider in selecting benchmark events (e.g., temperature magnitude, duration of the event, geographical area
impacted, etc.) the SDT is not in a position to provide that statistical basis or determine the appropriateness of any
specific event. Therefore, to ensure consistency across regions, it is necessary for the ERO to have the responsibility
for determining the suitability of benchmark events to represent probable future conditions. The ERO will maintain
a library of benchmark events and develop a process to incorporate additional events proposed by responsible
entities. Responsible entities will then have access to vetted benchmark weather data in a format that can be
incorporated into benchmark planning cases.
Since any region can experience temperatures that are higher or lower than normal, each responsible entity must
select at least one case that includes hotter temperature assumptions and one case that includes colder temperature
assumptions. While it is understood that, for example, one region may typically experience hotter summers and
milder winters than another region, both a hotter than average summer and a colder than average winter could result
in reliability concerns. Therefore, the requirement is for at least one case specific to extreme heat and at least one
case specific to extreme cold conditions to be studied for the Extreme Temperature Assessment.

NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
8

Requirement R3
Requirement R3 aligns with directives in FERC Order 896, emphasizing the importance of coordinating the
development of benchmark planning cases amongst impacted responsible entities, where the scope of extreme
temperature event studies will likely cover large geographical areas exceeding smaller individual planning areas.
Requirement R3, Part 3.1 addresses directives in FERC Order 896, paragraph 50, to consider the wide-area impacts
of extreme heat and cold weather and define the wide-area boundaries in transmission planning studies. Additionally,
Requirement R3, Part 3.2 addresses directives in FERC Order 896, paragraph 124, which requires the use of sensitivity
cases to demonstrate the impact of changes to the assumptions used in the benchmark planning case(s). Specifically,
paragraph 124 emphasizes the importance of including conditions that vary with temperature such as load,
generation, and system transfers.

NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
9

Requirement R4
The Extreme Temperature Assessment requires System models, developed in accordance with the MOD-032
standard, for conducting steady state power flow and stability analysis. This aligns with directives in FERC Order 896,
emphasizing the requirement of both steady state and transient stability analysis be conducted for extreme heat and
cold weather events as part of transmission planning studies. Requirement R4 is consistent with how Reliability
Standard TPL-001-5.1 cross-references Reliability Standard MOD-032, which establishes consistent modeling data
requirements and reporting procedures for the development of planning horizon cases necessary to support analysis
of the reliability of the interconnected system.

NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
10

Requirement R5
Requirement R5 was drafted to require each responsible entity to set the criteria needed for limits that will be used
to evaluate the voltage results from the Extreme Temperature Assessment. The establishment of these criteria allows
auditors to compare the results of the assessment with the established criteria.

NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
11

Requirement R6
This requirement addresses directives in FERC Order No. 896 for responsible entities to perform both steady state
and transient stability (dynamic) analyses to ensure that the system has been thoroughly assessed for instability,
uncontrolled separation, and Cascading in both the steady state and the transient stability realms.
Adequate criteria should be built into the Extreme Temperature Assessment when performing steady state and
transient stability analyses and should be documented clearly. The identification of instability, uncontrolled
separation, and Cascading analyses should include thorough technical criteria and supporting information.

NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
12

Requirement R7
This requirement addresses directives in FERC Order No. 896 to define a set of Contingencies that responsible entities
will be required to consider when conducting wide-area studies of extreme heat and cold weather events. FERC’s
preference to rely on established Contingency definitions, “[w]e believe that it is necessary to establish a set of
common contingencies for all responsible entities to analyze. Required contingencies, such as those listed in Table 1
of Reliability Standard TPL-001-5.1 (i.e., category P1 through P7), establish common planning events that set the
starting point for transmission system planning assessments,” was also considered by the SDT. It is necessary to
establish a set of common Contingencies for all responsible entities to analyze. Requiring the study of predefined
Contingencies, such as those listed in Table 1, will ensure a level of uniformity across planning regions, considering
that extreme heat and cold weather events often exceed the geographic boundaries of most existing planning
footprints. Defining the Contingencies in Table 1 consistently with Table 1 of Reliability Standard TPL-001-5.1 meets
FERC’s preference for commonality.
If feasible, all Contingencies listed in Table 1 should be considered for evaluation by the responsible entity; however,
the language affords flexibility in identifying the most appropriate Contingencies. As such, the responsible entity
should implement a method and establish sufficient supporting rationale to ensure Contingencies that are expected
to produce more severe System impacts within its planning area are adequately identified.
Some, but not all, items to consider when developing the rationale are:
• Past studies,
• Subject matter expert knowledge and judgment of the responsible entity’s System (to be supplemented with
data or analysis), and
• Historical data from past operating events.

NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
13

Requirement R8
Requirement R8 was drafted to provide clarity on the following:
1. Frequency of the Extreme Temperature Assessment (Assessment):
Due to significant level of data collection and coordination between the Planning Coordinator(s) and
Transmission Planner(s) for the potential wide-area extreme cold or extreme heat benchmark events, as
well as the need to document the assumptions and study results, the SDT opined that performing and
completing of the Assessment once every five calendar years is a reasonable timeframe to allow
responsible entities to coordinate, prepare, perform and document the Assessment study results. To the
extent that responsible entities want to perform more than one set of Assessment for an extreme heat and
extreme cold benchmark event, they can do so, but the minimum requirement is once every five calendar
years to perform and complete one set of Assessment.
2. What planning study cases are required?
The Requirement R8 includes the following minimum number of assessments to complete the Extreme
Temperature Assessment and address FERC 896 directives per paragraph 111 that “direct NERC to
require in the proposed new or modified Reliability Standard that responsible entities perform both steady
state and transient stability (dynamic) analyses in the extreme heat and cold weather planning studies”. In
addition, Requirement R8 also addresses FERC 896 directives per paragraph 124 that “require the use of
sensitivity cases to demonstrate the impact of changes to the assumptions used in the benchmark planning
case”. Requirement R8 also addresses FERC directives per paragraph 124 that sensitivity cases “should
consider including conditions that vary with temperature such as load, generation, and system transfers.”
Since the benchmark planning case(s) already include System conditions under extreme heat or extreme
cold events, the sensitivity analysis is to include, at a minimum, changes to one of the assumptions in
generation, loads or transfers. Since the minimum requirement includes changes to one of these
conditions, the PCs and the TPs can include further sensitivity assessments to change more conditions if
they choose to do so.
The following provides the minimum number of assessments required to complete the Extreme
Temperature Assessment for the benchmark planning cases, as well as for sensitivity assessments.
Type of Extreme
Temperature
Assessment

Extreme Cold Temperature
Event

Extreme Heat
Temperature Event

Total

Benchmark Planning
Case Analysis

A minimum of one extreme
cold benchmark planning
case assessment

A minimum of one extreme
heat benchmark planning
case assessment

Total Minimum: Two
benchmark planning
case assessments

Sensitivity Analysis

A minimum of one
sensitivity study case for
one of the following:

A minimum of one
sensitivity study case for
one of the following:

Total Minimum: Two
sensitivity cases
analysis

1. Changes in generation
availability, or

1. Changes in generation
availability, or

2. Changes in load level
(real and reactive), or

2. Changes in load level
(real and reactive), or

NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
14

Type of Extreme
Temperature
Assessment

Extreme Cold Temperature
Event
3. Changes in transfer
level

Extreme Heat
Temperature Event

Total

3. Changes in transfer
level

Total

A minimum total of
four assessments to
complete the
Extreme
Temperature
Assessment

3. What are the types of power flow related analyses?
There are two types of power flow related analyses: a steady-state and a stability analysis that are applied
for the minimum of four planning study cases as identified in the above table. This requirement is to satisfy
FERC Order 896 directive paragraph 111.

NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
15

Requirement R9
FERC Order 896 identifies a deficiency in the existing NERC TPL-001-5.1 Transmission Planning Reliability Standard
where “planning coordinators and transmission planners are required to evaluate possible actions to reduce the
likelihood or mitigate the consequences of extreme temperature events but are not obligated to develop corrective
action plans” (¶139).
Given potential severe consequences of extreme cold and extreme heat events, FERC Order 896 raises the bar and
“directs NERC to require in the new or modified Reliability Standard the development of extreme weather corrective
action plans for specified instances when performance standards are not met” (¶152).
Due to higher likelihood of P1 Contingencies, performance requirements for P0 and P1 Contingencies are held to a
higher performance standard, and Corrective Action Plans (CAPs) are required to address performance deficiencies
for P0 and P1 Contingencies in the Extreme Temperature Assessments.
Furthermore, having a CAP requirement for P0 and P1 contingencies aligns with ensuring resilience during future
extreme cold and extreme heat events, when transmission system is required to be P1-secure (using contingency
analysis, voltage stability and transient stability).
As per Order 896, paragraph 94, it is clarified that resource adequacy benchmarks are not within the scope of TPL008-1. The intent of the standard is to evaluate benchmark events where sufficient generation is available to supply
load. However, under an extreme heat or extreme cold temperature condition, there may instances where the
benchmark planning cases and/or sensitivity cases may not have sufficient available generation to supply the load. In
these scenarios, it may be acceptable for the responsible entity to either curtail load, or model most likely future
resources in the interconnection queue, to achieve a solution for the benchmark planning case. Under these
conditions, the amount of load curtailment or potential new resources assumed in the benchmark planning cases
need to be documented Extreme Temperature Assessment to be reported to the applicable regulatory authorities or
governing bodies responsible for retail electric service issues.
Given that a P0 Contingency represents a continuous system condition without any system disturbances, the SDT
opined that load shedding should not be considered as a CAP. However, the SDT has determined that load curtailment
may be considered for a P1 Contingency as a CAP where load shed is allowed to prevent system-wide failures and
ensuring the continued operation of essential services under a critical P1 Contingency in the extreme heat and cold
events. The SDT also emphasizes that other alternative solutions, other than firm load curtailment, are evaluated in
higher priorities. In the event that firm Load shed is included in the CAP for a P1 contingency, the responsible entity
shall document the alternative(s) considered, as mentioned in Requirement R10, and notify the applicable regulatory
authorities or governing bodies responsible for retail electric service issues.

NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
16

Requirement R10
The requirement for responsible entities to assess and document possible actions designed to reduce the likelihood
or mitigate the consequences of System instability, uncontrolled separation, or Cascading failures during P2, P4, P5,
and P7 Contingencies is in response to directives outlined in FERC Order 896.
The P2, P4, P5, and P7 Contingencies involve multiple element outages resulting from a single event, making them
relatively less likely to occur compared to P0 and P1 Contingencies but potentially causing more severe system
impacts. Considering both the likelihood of these Contingencies and the fact that the Extreme Temperature
Assessment already addresses low-probability system conditions, the SDT determined that no corrective action is
required for P2, P3, P4, and P7 Contingencies. However, due to their potential severity resulting from singleContingency multiple element outages, the SDT believes it is appropriate for responsible entities to at least evaluate
and document possible mitigation actions to reduce the likelihood or mitigate the consequences and adverse
impacts.
The SDT finds it reasonable to exclude P3 and P6 Contingencies from the Extreme Temperature Assessment. Part of
the decision stems from the complexity of P3 and P6, which involve multiple element outages triggered by multiple
Contingencies, with system adjustments allowed between them. Consequently, the occurrence likelihood of P3 and
P6 could be even lower compared to P2, P4, P5, and P7 Contingencies. Moreover, aligning with the directives set
forth in FERC Order 896, which emphasizes the importance of incorporating derated generation, transmission
capacity, and the availability of generation and transmission in the development of benchmark planning cases, it
becomes imperative for responsible entities to consider potential concurrent or correlated generation and
transmission outages and derates within relevant benchmark planning cases. This ensures that the benchmark
planning case accurately reflects system conditions under extreme temperatures, with generation and transmission
outages already factored in. Therefore, the SDT believes excluding P3 and P6 is justified, as generation and
transmission outages are already accounted for within the benchmark planning cases.

NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
17

Requirement R11
The requirement for responsible entities to share Extreme Temperature Assessment results aligns with directives in
FERC Order 896, emphasizing coordination and sharing of study findings. It ensures collaboration among stakeholders
and timely dissemination of critical information to entities with reliability-related needs. This fosters a collective
understanding of reliability concerns identified in wide-area studies, thereby enhancing overall grid reliability.

NERC | Technical Rationale and Justification for TPL-008-1 | March 2024
18

Unofficial Comment Form

Project 2023-07 Transmission Planning Performance Requirements for
Extreme Weather
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on draft one of TPL-008-1 – Transmission System Planning Performance
Requirements for Extreme Temperature Events by 8 p.m. Eastern, Friday, May 3, 2024.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Standards
Developer, Jordan Mallory (via email), or at 470-479-7538.
Background Information

On June 15, 2023, FERC issued FERC Order No. 896 that acknowledges the “challenges associated with
planning for extreme heat and cold weather events, particularly those that occur during periods when the
Bulk-Power System must meet unexpectedly high demand. Extreme heat and cold weather events have
occurred with greater frequency in recent years, and are projected to occur with even greater frequency
in the future. These events have shown that load shed during extreme temperature result in unacceptable
risk to life and have extreme economic impact. As such, the impact of concurrent failures of Bulk-Power
System generation and transmission equipment and the potential for cascading outages that may be
caused by extreme heat and cold weather events should be studied and corrective actions should be
identified and implemented.” 1
Therefore, the Commission directed in FERC Order No. 896 to develop a new or modified Reliability
Standard to address a lack of long-term planning requirement(s) for extreme heat and cold weather
events. Specifically, FERC directed NERC to develop modifications to Reliability Standard TPL-001-5.1 or a
new Reliability Standard, to require the following: (1) development of benchmark planning cases based on
major prior extreme heat and cold weather events and/or meteorological projections; (2) planning for
extreme heat and cold weather events using steady state and transient stability analyses expanded to
cover a range of extreme weather scenarios including the expected resource mix's availability during
extreme heat and cold weather conditions, and including the wide-area impacts of extreme heat and cold
weather; and (3) development of corrective action plans that mitigate any instances where performance
requirements for extreme heat and cold weather events are not met.

1

N. Am. Elec. Reliability Corp., 183 FERC ¶ 61,191 (2023) (FERC Order), Final Rule. eLibrary | File List (ferc.gov)

RELIABILITY | RESILIENCE | SECURITY

Questions

1. Do you agree with the proposed definition of Extreme Temperature Assessment? If you do not
agree, please provide your recommendation and, if appropriate, technical justification.
Yes
No
Comments:
2. Do you agree with the proposed TPL-008-1 Reliability Standard Requirement R1? If you do not
agree, please provide your recommendation and, if appropriate, technical justification.
Yes
No
Comments:
3. Do you agree with the proposed TPL-008-1 Reliability Standard Requirement R2 (Benchmark
events)? If you do not agree, please provide your recommendation and, if appropriate, technical
or procedural justification.
Yes
No
Comments:
4. Do you agree with the proposed TPL-008-1 Reliability Standard Requirements R3 – R8 (benchmark
planning cases and analyses)? If you do not agree, please provide your recommendation and, if
appropriate, technical or procedural justification.
Yes
No
Comments:
5. Do you agree with the proposed TPL-008-1 Reliability Standard Requirements R9 – R10 (CAPs and
possible actions)? If you do not agree, please provide your recommendation and, if appropriate,
technical or procedural justification.
Yes
No
Comments:

Unofficial Comment Form
Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather | March 2024

6. Do you agree with the proposed TPL-008-1 Reliability Standard Requirement R11 (Sharing Extreme
Temperature Assessment results)? If you do not agree, please provide your recommendation and,
if appropriate, technical or procedural justification.
Yes
No
Comments:
7. Do you agree with the proposed TPL-008-1 Table 1? If you do not agree, please provide your
recommendation and technical justification.
Yes
No
Comments:
8. The Standard Drafting Team (SDT) is proposing a phased-in implementation plan approach. Do you
agree with the proposed phased-in timeframes? If you do not agree, please provide your
recommendation and technical justification.
Yes
No
Comments:
9. Provide any additional comments for the SDT to consider, including the provided technical
rationale document, if desired.
Comments:

Unofficial Comment Form
Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather | March 2024

Violation Risk Factor and Violation Severity Level
Justifications

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
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 2023-07 Transmission System Planning Performance Requirements for Extreme Weather. 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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

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
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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

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 Justifications for TPL-008-1, Requirement R1
Proposed VRF

Lower

NERC VRF Discussion

A VRF of Lower is appropriate due to the fact that the Planning Coordinators, in conjunction with its
Transmission Planner(s) will determine joint responsibilities for requirements throughout TPL-008-1.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

5

VSLs for TPL-008-1, Requirement R1
Lower
N/A

Moderate
N/A

High
N/A

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

Severe
The Planning Coordinator, in
conjunction with its Transmission
Planner(s), failed to determine and
identify individual and joint
responsibilities for performing the
required studies for the Extreme
Temperature Assessment.

6

VSL Justifications for TPL-008-1, Requirement R1
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the Planning Coordinator and Transmission Planner to determine
who completes the responsibilities throughout TPL-008-1. The responsibilities documentation will either be
developed or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

7

VRF Justifications for TPL-008-1, Requirement R2
Proposed VRF

High

NERC VRF Discussion

A VRF of high is appropriate due to the fact that selecting a benchmark event to perform an extreme
temperature assessment can affect the grid based on planning analysis for future events.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

8

VSLs for TPL-008-1, Requirement R2
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity did not
select an extreme heat benchmark
event or extreme cold benchmark
event from the ERO approved
benchmark library.

The responsible entity did not
select an extreme heat benchmark
event and extreme cold benchmark
event from the ERO approved
benchmark library.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

9

VSL Justifications for TPL-008-1, Requirement R2
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

This VSL has been assigned as a binary due to the benchmark event needing to be selected for benchmark
planning cases to be completed. You either select a benchmark event or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

10

VRF Justifications for TPL-008-1, Requirement R3
Proposed VRF

High

NERC VRF Discussion

A VRF of high is appropriate due to the fact that it is important to develop and maintain System models within
an entity’s planning area for performing Extreme Temperature Assessments. Connecting to MOD-032 to provide
important data needed to assist entities with System models is also important for accurate information to be
used.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

11

VSLs for TPL-008-1, Requirement R3
Lower
N/A

Moderate
N/A

High
N/A

Severe
The Planning Coordinator did not
develop or implement a process for
coordinating the development of
benchmark planning cases among
impacted Planning Coordinator(s)
Transmission Planner(s), and other
designated study entities.
OR
The Planning Coordinator
developed and implemented a
process for coordinating the
development of benchmark
planning cases among impacted
Planning Coordinator(s),
Transmission Planner(s), and other
designated study entities, but this
process did not define the planning
study area boundary based off the
selected benchmark events.
OR
The Planning Coordinator
developed and implemented a
process for coordinating the
development of benchmark
planning cases among impacted
Planning Coordinator(s),
Transmission Planner(s), and other
designated study entities, but this
process did not modify the

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

12

benchmark planning cases to
include seasonal and temperature
dependent adjustments load,
generation, Transmission, and
transfers.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

13

VSL Justifications for TPL-008-1, Requirement R3
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either develops and maintains the System
models within its planning area or it does not develop and maintain the System models within its planning area.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

14

VRF Justifications for TPL-008-1, Requirement R4
Proposed VRF

Medium

NERC VRF Discussion

A VRF of Medium

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

15

VSLs for TPL-008-1, Requirement R4
Lower
N/A

Moderate
N/A

High
N/A

Severe
The responsible entity did not
develop or maintain System models
of the responsible entity’s planning
area for performing Extreme
Temperature Assessment.
OR
The responsible entity developed
and maintained System models for
performing Extreme Temperature
Assessment, but the System model
did not use data consistent with
that provided in accordance with
the MOD-032 standard
supplemented by other sources as
needed.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

16

VSL Justifications for TPL-008-1, Requirement R4
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the Planning Coordinator to develop and implement a process for
coordinating the development of benchmark planning cases. The benchmark planning cases will either be
developed and implemented or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

17

VRF Justifications for TPL-008-1, Requirement R5
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate due to the importance of having a criteria for acceptable System steady state
voltage limits of post-Contingency voltage deviations for performing Extreme Temperature Assessments.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

18

VSLs for TPL-008-1, Requirement R5
Lower
N/A

Moderate
N/A

High
N/A

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

Severe
The responsible entity, as
determined in Requirement R1, did
not have criteria for acceptable
System steady state voltage limits
and post-Contingency voltage
deviations for performing Extreme
Temperature Assessment.

19

VSL Justifications for TPL-008-1, Requirement R5
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either having acceptable criteria for System
steady state voltage limits and post-contingency voltage deviations or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

20

VRF Justifications for TPL-008-1, Requirement R6
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate due to the importance of defining and documenting the criteria or methodology for
System instability, uncontrolled separation, or Cascading.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

21

VSLs for TPL-008-1, Requirement R6
Lower
N/A

Moderate
N/A

High
N/A

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

Severe
The responsible entity failed to
define and document, the criteria
or methodology used in the
analysis to identify System
instability, uncontrolled separation,
or Cascading.

22

VSL Justifications for TPL-008-1, Requirement R6
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

23

VRF Justifications for TPL-008-1, Requirement R7
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate for this requirement. Identifying Contingencies for performing Extreme
Temperature Assessments for each of the event categories in Table 1 can directly impact the BES.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

24

VSLs for TPL-008-1, Requirement R7
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity, as
determined in Requirement R1,
identified Contingencies for
performing Extreme Temperature
Assessment for each of the event
categories in Table 1 that are
expected to produce more severe
System impacts within its planning
area, but did not include the
rationale for those Contingencies
selected for evaluation as
supporting documentation.

The responsible entity, as
determined in Requirement R1, did
not identify Contingencies for
performing Extreme Temperature
Assessment for each of the event
categories in Table 1 that are
expected to produce more severe
System impacts within its planning
area.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

25

VSL Justifications for TPL-008-1, Requirement R7
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

26

VRF Justifications for TPL-008-1, Requirement R8
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate due to the importance of performing an Extreme Temperature Assessment every 5
years.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

27

VSLs for TPL-008-1, Requirement R8
Lower
The responsible entity, as
determined in Requirement R1,
completed an Extreme
Temperature Assessment, but it
was completed less than or equal
to six months late.

Moderate
The responsible entity, as
determined in Requirement R1,
completed an Extreme
Temperature Assessment, but it
was completed more than six
months but less than or equal to 12
months late.

High
The responsible entity, as
determined in Requirement R1,
completed an Extreme
Temperature Assessment, but it
was completed more than 12
months but less than or equal to
18 months late.

Severe
The responsible entity, as
determined in Requirement R1,
completed an Extreme
Temperature Assessment, but it
was more than 18 months late.
OR
The responsible entity, as
determined in Requirement R1, did
not complete an Extreme
Temperature Assessment.
OR
The responsible entity, as
determined in Requirement R1,
completed an Extreme
Temperature Assessment, but it
was missing one or more of the
required elements in Requirement
R8.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

28

VSL Justifications for TPL-008-1, Requirement R8
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

29

VRF Justifications for TPL-008-1, Requirement R9
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate for this requirement. Developing a Corrective Action Plan is important to the BES as
it assists entities when Systems are unable to meet performance requirements.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

30

VSLs for TPL-008-1, Requirement R9
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity, as
determined in Requirement R1,
failed to solicit feedback from,
applicable regulatory authorities or
governing bodies responsible for
retail electric service issues.

The responsible entity, as
determined in Requirement R1,
failed to develop a Corrective
Action Plan when the benchmark
planning case study results indicate
the System is unable to meet
performance requirements for the
Table 1 P0 or P1 Contingencies.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

31

VSL Justifications for TPL-008-1, Requirement R9
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either having acceptable criteria for System
steady state voltage limits and post-contingency voltage deviations or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

32

VRF Justifications for TPL-008-1, Requirement R10
Proposed VRF

Lower

NERC VRF Discussion

A VRF of lower has been assigned to Requirement R10. Documenting possible actions to reduce the likelihood
or mitigate the consequences and adverse impacts are administrative in nature.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

33

VSLs for TPL-008-1, Requirement R10
Lower
N/A

Moderate
N/A

High
N/A

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | March 2024

Severe
Each responsible entity, as
determined in Requirement R1,
failed to evaluate and document
possible actions designed to reduce
the likelihood or mitigate the
consequences and adverse impacts
when the benchmark planning case
study results indicate the System
could result in instability,
uncontrolled separation, or
Cascading for the Table 1 P2, P4,
P5, and P7 Contingencies.

34

VSL Justifications for TPL-008-1, Requirement R10
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the fact that the responsible entity will either have evaluated and
documented possible actions to mitigate adverse impacts.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
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35

VRF Justifications for TPL-008-1, Requirement R11
Proposed VRF

Medium

NERC VRF Discussion

The VRF of Medium is appropriate because it could directly affect the electrical state or capability of the BES if
entities are not aware of the results from its Extreme Temperature Assessment results.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

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36

VSLs for TPL-008-1, Requirement R11
Lower

Moderate

High

Severe

The responsible entity, as
determined in Requirement R1,
distributed its Extreme
Temperature Assessment results to
functional entities having a
reliability related need who
requested the information in
writing, but it was more than 60
days but less than or equal to 80
days following the request.

The responsible entity, as
determined in Requirement R1,
distributed its Extreme
Temperature Assessment results to
functional entities having a
reliability related need who
requested the information in
writing, but it was more than 80
days but less than or equal to 100
days following the request.

The responsible entity, as
determined in Requirement R1,
distributed its Extreme
Temperature Assessment results to
functional entities having a
reliability related need who
requested the information in
writing, but it was more than 100
days but less than or equal to 120
days following the request.

The responsible entity, as
determined in Requirement R1,
distributed its Extreme
Temperature Assessment results to
functional entities having a
reliability related need who
requested the information in
writing, but it was more than 120
days following the request.
OR
The responsible entity, as
determined in Requirement R1, did
not distribute its Extreme
Temperature Assessment results to
functional entities having a
reliability related need who
requested the information in
writing.

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VSL Justifications for TPL-008-1, Requirement R11
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

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Consideration of FERC Order 896 Directives

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
March 2024
On June 15, 2023, FERC issued a Final Rulemaking to direct NERC to develop a new or modified Reliability Standard to address a lack of a longterm planning requirement(s) for extreme heat and cold weather events. Specifically, FERC directed NERC to develop modifications to
Reliability Standard TPL-001-5.1 or a new Reliability Standard, to require the following: (1) development of benchmark planning cases based on
major prior extreme heat and cold weather events and/or meteorological projections; (2) planning for extreme heat and cold weather events
using steady state and transient stability analyses expanded to cover a range of extreme weather scenarios including the expected resource
mix's availability during extreme heat and cold weather conditions, and including the wide-area impacts of extreme heat and cold weather;
and (3) development of corrective action plans that mitigate any instances where performance requirements for extreme heat and cold
weather events are not met. The below provides FERC Order 896 Directive language along with the drafting teams consideration of the
directives.

Directive Language

FERC Order 896 Directives

P35. “[W]e direct NERC to: (1) develop extreme heat and cold weather
benchmark events, and (2) require the development of benchmark
planning cases based on identified benchmark events.”
P 36: “…As recommended by commenters, NERC should consider the
examples of approaches for defining benchmark events identified in the
NOPR (e.g., the use of projected frequency or probability distribution).
NERC may also consider other approaches that achieve the objectives
outlined in this final rule.”

Consideration of Directives

The ERO will work with respective subject matter experts, including climate
experts, the six regions, etc., and develop extreme heat and extreme cold
weather benchmark events. An ERO-maintained library will be created, and
all developed extreme heat and extreme cold weather benchmark events
will be retained. From this library, responsible entities will be able to
review and select the appropriate benchmark events to assist with the
development of its benchmark planning cases.
The drafting team developed requirements within TPL-008-1 to require
responsible entities to select one extreme heat benchmark event and
extreme cold benchmark event from the approved ERO library

RELIABILITY | RESILIENCE | SECURITY

Directive Language

FERC Order 896 Directives

Consideration of Directives

(Requirement R2). After selecting its benchmark events, the responsible
entity is required to develop and implement a process for coordinating the
development of benchmark planning cases among the respective entities
(Requirement R3) and develop and maintain System models (Requirement
R4).

P38. “[I]n developing extreme heat and cold benchmark events, NERC shall
ensure that benchmark events reflect regional differences in climate and
weather patterns.”

The ERO will work with respective subject matter experts, including climate
experts, the six regions, etc., to ensure regional differences in climate and
weather patterns are reflected within the developed benchmark events.

P39. “We also direct NERC to include in the Reliability Standard the
framework and criteria that responsible entities shall use to develop from
the relevant benchmark event planning cases to represent potential
weather-related contingencies (e.g., concurrent/correlated generation and
transmission outages, derates) and expected future conditions of the
system such as changes in load, transfers, and generation resource mix,
and impacts on generators sensitive to extreme heat or cold, due to the
weather conditions indicated in the benchmark events. Developing such a
framework would provide a common design basis for responsible entities
to follow when creating benchmark planning cases. This would not only
help establish a clear set of expectations for responsible entities to follow
when developing benchmark planning events, but also facilitate auditing
and enforcement of the Standard.”

The directive is addressed in proposed TPL-008-1 through Requirement R3,
R4, and R8.

P40. “We also direct NERC to ensure the reliability standard contains
appropriate mechanisms for ensuring the benchmark event reflects up-todate meteorological data.”

Requirement R3 obligates the Planning Coordinator to develop and
implement a process to coordinate the development of the benchmark
planning cases.
Requirement R4 obligates the responsible entity to develop and maintain
System models for performing the Extreme Temperature Assessment
which represents projected System conditions based on the selected
benchmark events
Requirement R8 obligates the responsible entity to assess and complete an
Extreme Temperature Assessment for one of the years in the Long-Term
Transmission Planning Horizon, for the benchmark planning cases as well as
sensitivity analysis which includes changes to one of these conditions:
generation, real or reactive forecasted Load, or transfers.
The drafting team discussed a similar process to how BAL-003 gathers data.
It was determined that the ERO is in the best situation to provide a review
with the respective subject matter experts, including climate experts, the

Consideration of FERC Order 896 Directives
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Directive Language

FERC Order 896 Directives

P50. [W]e…direct NERC to require that transmission planning studies under
the new or revised Reliability Standard consider the wide-area impacts of
extreme heat and cold weather. We direct NERC to clearly describe the
process that an entity must use to define the wide-area boundaries. While
commenters provide various views in favor of both a geographical
approach and electrical approach to defining wide-area boundaries, we do
not adopt any one approach in this final rule…NERC should consider the
comments in this proceeding when developing a new or modified reliability
standard that considers the broad area impacts of extreme heat and cold
weather.”
P58. “[W]e…direct NERC to develop benchmark events for extreme heat
and cold weather events through the Reliability Standards development
process.”

Consideration of Directives

six regions, etc., and update the benchmark events to reflect up-to-date
meteorological data every 5 years via a NERC process document.
The SDT reviewed all the extreme weather events mentioned within the
FERC Order 896. The selected benchmark event will determine the
impacted wide area.
The directive is addressed in proposed TPL-008-1 through requirement R2
and R3 Part 3.1.

The ERO will work with respective subject matter experts, including climate
experts, the six regions, etc., to develop benchmark events. These events
will be uploaded to an ERO library where responsible entities will then
select their respective benchmark events from the ERO library to develop
the benchmark planning cases.
The directive is addressed in proposed TPL-008-1 through requirement R2.
Requirement R2 obligates the responsible entity to select one extreme
heat benchmark event and extreme cold benchmark event for performing
the Extreme Temperature Assessment, from the approved benchmark
library, maintained by the ERO.

P60. “[W]e…direct NERC to designate the type(s) of entities responsible for
developing benchmark planning cases and conducting wide-area studies
under the new or modified Reliability Standard…benchmark planning cases
should be developed by registered entities such as large planning
coordinators, or groups of planning coordinators, with the capability of
planning on a regional scope.”

The drafting team discussed that the Transmission Planner (TP) and/or
Planning Coordinator (PC) would be the responsible entities to address TPL008-1 Requirements. Requirement R1 obligates both the TP and PC to
identify individual and joint responsibilities.

Consideration of FERC Order 896 Directives
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Directive Language

FERC Order 896 Directives

P 61: “We believe the designated responsible entities should have certain
characteristics, including having a wide-area view of the Bulk-Power
System and the ability to conduct long-term planning studies across a wide
geographic area. The responsible entities should also have the planning
tools, expertise, processes, and procedures to develop benchmark planning
cases and analyze extreme weather events in the long-term planning
horizon.”
P 62: To comply with this directive, NERC may designate the tasks of
developing benchmark planning cases and conducting wide-area studies to
an existing functional entity or a group of functional entities (e.g., a group
of planning coordinators). NERC may also establish a new functional entity
registration to undertake these tasks. In the petition accompanying the
proposed Reliability Standard NERC should explain how the applicable
registered entity or entities meet the objectives outlined above.
P72. “[W]e direct NERC to require functional entities to share with the
entities responsible for developing benchmark planning cases and
conducting wide-area studies the system information necessary to develop
benchmark planning cases and conduct wide-area studies. Further,
responsible entities must share the study results with affected transmission
operators, transmission owners, generator owners, and other functional
entities with a reliability need for the studies.”

P73. “Because in this final rule we direct NERC to determine the
responsible entities that will be developing benchmark planning cases and

Consideration of Directives

The drafting team reviewed all the extreme weather events mentioned
within the FERC Order 896. The selected benchmark event will determine
the impacted wide area. Requirement R3 Part 3.1 obligates each the
responsible entity to define the planning study area boundary based on the
selected benchmark events.

The directive is addressed in proposed TPL-008-1 through requirement R3
and R11.
R3 obligates the Planning Coordinator to develop and implement a process
for coordinating the development of benchmark planning cases among
impacted Planning Coordinator(s), Transmission Planner(s), and other
designated study entities.
R11 obligates Planning Coordinator(s), Transmission Planner(s), and other
designated study entities to provide its Extreme Temperature Assessment
results within 60 calendar days of a request to any functional entity that
has a reliability related need and submits a written request for the
information.
The drafting team discussed and determined that data needed to address
the Extreme Temperature Assessment would still be appropriate through

Consideration of FERC Order 896 Directives
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Directive Language

FERC Order 896 Directives

conducting wide-area studies, it is possible that the selected responsible
entities under the new or modified Reliability Standard will not be able to
request and receive needed data pursuant to MOD-032-1, absent
modification to that Standard.”

Consideration of Directives

MOD-032 and additional functional entities are not needed throughout this
standards development process to address FERC Order 896.
The directive is addressed in proposed TPL-008-1 through Requirement R1,
R3 Part 3.1, R4 and R8.
Requirement R1 obligates the Planning Coordinator, in conjunction with its
Transmission Planner, to determine and identify each entity’s individual
and joint responsibilities for performing the studies needed to complete
the Extreme Temperature Assessment.

P76: “[W]e…direct NERC to address the requirement for wide-area
coordination through the standards development process, giving due
consideration to relevant factors identified by commenters in this
proceeding.”

The drafting team reviewed all the extreme weather events mentioned
within the FERC Order 896. The selected benchmark event will determine
the impacted wide area. Requirement R3 Part 3.1 obligates each the
responsible entity to define the planning study area boundary based on the
selected benchmark events.

P77. “[W]e direct NERC to require in the new or modified Reliability
Standard that responsible entities share the results of their wide-area
studies with other registered entities such as transmission operators,
transmission owners, and generator owners that have a reliability related
need for the studies.”

This directive is addressed in proposed TPL-008-1 Requirement R11.

P88. direct NERC to require under the new or revised Reliability Standard
the study of concurrent/correlated generator and transmission outages
due to extreme heat and cold events in benchmark events as described in
more detail below.

Requirement R11 obligates each responsible entity to provide the wide
area study results within 60 calendar days of a request to any functional
entity that has a reliability related need and has submitted a written
request for the information.
This directive is addressed in proposed TPL-008-1 through Requirement R3
Part 3.2. The responsible entity is obligated to modify the benchmark
planning cases to include seasonal and temperature dependent adjustment
for Load, generation, Transmission, and transfers which represent the
selected benchmark events.

Consideration of FERC Order 896 Directives
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Directive Language

FERC Order 896 Directives

P111. “[W]e direct NERC to require in the proposed new or modified
Reliability Standard that responsible entities perform both steady state and
transient stability (dynamic) analyses in the extreme heat and cold weather
planning studies. In a steady state analysis, the system components are
modeled as either in-service or out-of-service and the result is a single
point-in-time snapshot of the system in a state of operating equilibrium. A
transient stability (dynamic) analysis examines the system from the start to
the end of a disturbance to determine if the system regains a state of
operating equilibrium. Performing both analyses ensures that the system
has been thoroughly assessed for instability, uncontrolled separation, and
cascading failures in both the steady state and the transient stability
realms.” (internal citations omitted).
P112. “[W]e direct NERC to define a set of contingencies that responsible
entities will be required to consider when conducting wide-area studies of
extreme heat and cold weather events under the new or modified
Reliability Standard. We believe that it is necessary to establish a set of
common contingencies for all responsible entities to analyze. Required
contingencies, such as those listed in Table 1 of Reliability Standard TPL001-5.1 (i.e., category P1 through P7), establish common planning events
that set the starting point for transmission system planning assessments.
Requiring the study of predefined contingencies will ensure a level of
uniformity across planning regions—a feature that will be necessary in the
new or revised Reliability Standard considering that extreme heat and cold
weather events often exceed the geographic boundaries of most existing
planning footprints.”

Consideration of Directives

This directive is addressed in proposed TPL-008-1 through Requirement R8
and Table 1.
Requirement R8 requires the documentation of results of both steady state
and stability analyses.
Table 1 obligates each responsible entity to perform both steady state and
stability analyses and compare the study results against performance
criteria.

TPL-008-1 meets this directive by requiring each responsible entity to
identify Contingencies for performing the Extreme Temperature
Assessment. (See R7 and Table 1.) The Contingency categories in Table 1 of
TPL-008 correspond to the well-established Contingency events defined in
TPL-001.

P113: “[T]he contingencies required in the new or revised Reliability
Standards should reflect the complexities of transmission system planning
studies for extreme heat and cold weather events.”

Consideration of FERC Order 896 Directives
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Directive Language

FERC Order 896 Directives

P116. “[W]e direct NERC to require in the new or modified Reliability
Standard that responsible entities model demand load response in their
extreme weather event planning area. As indicated by several
commenters, because demand load response is generally a mitigating
action that involves reducing distribution load during periods of stress to
stabilize the Bulk-Power System, its effect during an extreme weather
event should be modeled.”
P 117: “[I]n addressing this directive, we expect NERC to determine
whether responsible entities will need to take additional steps to ensure
that the impacts of demand load response are accurately modeled in
extreme weather studies, such as by analyzing demand load response as a
sensitivity, as is currently the case under Reliability Standard TPL-001-5.1.”
P124. “[W]e direct NERC to require the use of sensitivity cases to
demonstrate the impact of changes to the assumptions used in the
benchmark planning case. Sensitivity analyses help a transmission planner
to determine if the results of the base case are sensitive to changes in the
inputs. The use of sensitivity analyses is particularly necessary when
studying extreme heat and cold events because some of the assumptions
made when developing a base case may change if temperatures change –
for example, during extreme cold events, load may increase as
temperatures decrease, while a decrease in temperature may result in a
decrease in generation. We AEP, and we direct NERC to define during the
Reliability Standard development process a baseline set of sensitivities for
the new or modified Reliability Standard. While we do not require the
inclusion of any specific sensitivity in this final rule, NERC should consider
including conditions that vary with temperature such as load, generation,
and system transfers.”

Consideration of Directives

TPL-008-1 meets this directive by requiring each responsible entity to
develop and maintain System models within its planning area consistent
with that of MOD-032 standard. (See R4.)
Specifically, Attachment 1 of MOD-032 requires information requested by
the Planning Coordinator or Transmission Planner necessary for modeling
purposes.

TPL-008-1 meets this directive by requiring each responsible entity to
perform steady state and stability analyses on benchmark planning cases
(R8.1) and sensitivity cases (R8.2). Furthermore, R8.2 provides a baseline
set of variable conditions that include changes to generation, load, or
transfers that are expected to change with extreme heat or extreme cold
temperatures.
.

P125. “We…believe that responsible entities should be free to study
additional sensitivities relevant to their planning areas…cooperation will be
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Directive Language

FERC Order 896 Directives

necessary between responsible entities conducting extreme heat and
extreme cold weather studies and other registered entities within their
extreme weather study footprints to ensure the selection of appropriate
sensitivities.”
P134. “[W]e directs NERC to require in the new or modified Reliability
Standard the use of planning methods that ensure adequate consideration
of the broad characteristics of extreme heat and cold weather conditions.
We further direct NERC to determine during the standard development
process whether probabilistic elements can be incorporated into the new
or modified Reliability Standard and implemented presently by responsible
entities. If NERC identifies probabilistic elements which responsible entities
can feasibly implement and that would improve upon existing planning
practices, we expect the inclusion of those methods in the proposed
Reliability Standard.”

P138. “[W]e direct NERC to identify during the standard development
process any probabilistic planning methods that would improve upon

Consideration of Directives

The Standard Drafting Team discussed probabilistic elements and
determined while probabilistic analysis would be a good step forward, it
would be better suited for the future as the methodology, process, and
tools mature.
A specific example could be that future updates or revision to TPL-008 may
provide an avenue for incorporating probabilistic elements into the
planning process, allowing for a more robust and accurate assessment of
system reliability and resilience.
Probabilistic assessment of generation and transmission facilities for the
benchmark planning cases was discussed during the process of drafting the
TPL-008-1 standard. However, based on the actual extreme heat and
extreme cold events that have occurred, outages for generation and
transmission facilities were unique for each of these events. Thus, it was
challenging to draw correlation for the outages that occurred for different
extreme heat and cold events for different regions and different
timeframe. In addition, the data that were available from these events
were limited to perform an adequate probabilistic assessment. Due to
these reasons, the Standard Drafting Team has decided not to pursue any
probabilistic assessment for the current TPL-008-1 standard. This, however,
does not preclude future development of probabilistic assessment when
having additional data, as well as mature methodology, process and tools
that can provide meaningful probabilistic assessment for generation and
transmission outages under extreme temperature conditions.
Please see the response above for P134.

Consideration of FERC Order 896 Directives
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Directive Language

FERC Order 896 Directives

existing planning practices, but that NERC deems infeasible to include in
the proposed Reliability Standard at this time. If any such methods are
identified, NERC shall describe in its petition for approval of the proposed
Reliability Standard the barriers preventing the implementation of those
probabilistic elements. We intend to use this information to determine
whether and what next steps may be warranted to facilitate the use of
probabilistic methods in transmission system planning practices.”
P152. “[W]e direct NERC to require in the new or modified Reliability
Standard the development of extreme weather corrective action plans for
specified instances when performance standards are not met. In addition,
as explained below, we direct NERC to develop certain processes to
facilitate interaction and coordination with applicable regulatory
authorities or governing bodies responsible for retail electric service as
appropriate in implementing a corrective action plan.”

Consideration of Directives

The directive is addressed in the proposed TPL-008-1 Requirement R9.
When the benchmark planning case study results indicate the System is
unable to meet performance requirements for P0 and P1 Contingencies,
Corrective Action Plans must be developed. Additionally, the responsible
entities shall share their Corrective Action Plans with, and solicit feedback
from, applicable regulatory authorities or governing bodies responsible for
retail electric service issues.

P155: “[T]he Commission is not directing any specific result or content of
the corrective action plan.”
P157. “[W]e direct NERC to require in the new or modified Reliability
Standard the development of corrective action plans that include
mitigation for specified instances where performance requirements for
extreme heat and cold events are not met—i.e., when certain studies
conducted under the Standard show that an extreme heat or cold event
would result in cascading outages, uncontrolled separation, or instability.”
P158: “[W]e give NERC in this final rule the flexibility to specify the
circumstances that require the development of a corrective action plan.”
P165. “[w]e direct NERC to require in the new or modified Reliability
Standard that responsible entities share their corrective action plans with,
and solicit feedback from, applicable regulatory authorities or governing
bodies responsible for retail electric service issues.”

The directive is addressed in the proposed TPL-008-1 Requirement R9.
When the benchmark planning case study results indicate the system is
unable to meet performance requirements for P0 and P1 Contingencies,
Corrective Action Plans must be developed.

The directive is addressed in the proposed TPL-008-1 Requirement R9.

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Directive Language

FERC Order 896 Directives

P167. “Further, because an important goal of transmission planning is to
avoid load shed, any responsible entity that includes non-consequential
load loss in its corrective action plan should also identify and share with
applicable regulatory authorities or governing bodies responsible for retail
electric service alternative corrective actions that would, if approved and
implemented, avoid the use of load shedding.”
P188. “[W]e direct NERC to submit a new or modified Reliability Standard
within 18 months of the date of publication of this final rule in the Federal
Register. Further, we direct NERC to propose an implementation timeline
for the new or modified Reliability Standard, with implementation
beginning no later than 12 months after the effective date of a Commission
order approving the proposed Reliability Standard.”
P193. “[W]e direct NERC to establish an implementation timeline for the
proposed Reliability Standard. In complying with this directive, NERC will
have discretion to develop a phased-in implementation timeline for the
different requirements of the proposed Reliability Standard (i.e.,
developing benchmark cases, conducting studies, developing corrective
action plans). However, this phased-in implementation must begin within
12 months of the effective date of a Commission order approving the
proposed Reliability Standard and must include a clear deadline for
implementation of all requirements.”

Consideration of Directives
R9 obligates the responsible entities shall share their Corrective
Action Plans with, and solicit feedback from, applicable regulatory
authorities or governing bodies responsible for retail electric service
issues.
This directive is addressed in proposed TPL-008-1 Requirement R9.

Where Load shed is allowed as an element of a Corrective Action Plan for
the Table 1 P1 Contingency, the responsible entity shall document the
alternative(s) considered, as mentioned in Requirement R10, and notify the
applicable regulatory authorities or governing bodies responsible for retail
electric service issues.
The directive is addressed with the publication of TPL-008-1 and will be
filed with the regulatory government no later than December 15, 2024,
within 18 months of the date of publication of Order 896.

The implementation plan addresses Requirement R1 becoming effective 12
months from the effective date of the Commission order approving the
TPL-008-1. In addition, phased-in approaches have been provided for other
Requirements needing additional time. See the TPL-008-1 Implementation
Plan.

Consideration of FERC Order 896 Directives
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Public

Standards Announcement

Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather
Formal Comment Period Open through May 3, 2024
Ballot Pools Forming through April 18, 2024
Now Available

A 45-day formal comment period for draft one of TPL-008-1 – Transmission System Planning
Performance Requirements for Extreme Temperature Events is open through 8 p.m. Eastern,
Friday, May 3, 2024.
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. An unofficial Word
version of the comment form is posted on the project page.
Reminder Regarding Corporate RBB Memberships

Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more
than the one permitted representative in a particular Segment must withdraw the duplicate
membership(s) prior to joining new ballot pools or voting on anything as part of an existing ballot pool.
Contact [email protected] to assist with the removal of any duplicate registrations.
Ballot Pools

Ballot pools are being formed through 8 p.m. Eastern, Thursday, April 18, 2024. Registered Ballot
Body members can join the ballot pools here.
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p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
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RELIABILITY | RESILIENCE | SECURITY

Limited Disclosure

Next Steps

Initial ballots for the standard and implementation plan, as well as a non-binding poll of the associated
Violation Risk Factors and Violation Severity Levels will be conducted April 24 – May 3, 2024.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Jordan Mallory (via email) or at 404-4797358. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists" from the
"Service" drop-down menu and specify “Project 2023-07 Transmission Planning Performance Requirements
for Extreme Weather observer list” in the Description Box.

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 2023-07 Transmission Planning Performance Requirements for Extreme Weather | March 20, 2024

2

Comment Report
Project Name:

2023-07 Transmission Planning Performance Requirements for Extreme Weather | Draft 1

Comment Period Start Date:

3/20/2024

Comment Period End Date:

5/3/2024

Associated Ballots:

2023-07 Transmission Planning Performance Requirements for Extreme Weather Implementation Plan IN 1 OT
2023-07 Transmission Planning Performance Requirements for Extreme Weather TPL-008-1 IN 1 ST

There were 78 sets of responses, including comments from approximately 179 different people from approximately 99 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. Do you agree with the proposed definition of Extreme Temperature Assessment? If you do not agree, please provide your recommendation
and, if appropriate, technical justification.
2. Do you agree with the proposed TPL-008-1 Reliability Standard Requirement R1? If you do not agree, please provide your recommendation
and, if appropriate, technical justification.
3. Do you agree with the proposed TPL-008-1 Reliability Standard Requirement R2 (Benchmark events)? If you do not agree, please provide
your recommendation and, if appropriate, technical or procedural justification.
4. Do you agree with the proposed TPL-008-1 Reliability Standard Requirements R3 – R8 (benchmark planning cases and analyses)? If you do
not agree, please provide your recommendation and, if appropriate, technical or procedural justification.
5. Do you agree with the proposed TPL-008-1 Reliability Standard Requirements R9 – R10 (CAPs and possible actions)? If you do not agree,
please provide your recommendation and, if appropriate, technical or procedural justification.
6. Do you agree with the proposed TPL-008-1 Reliability Standard Requirement R11 (Sharing Extreme Temperature Assessment results)? If
you do not agree, please provide your recommendation and, if appropriate, technical or procedural justification.
7. Do you agree with the proposed TPL-008-1 Table 1? If you do not agree, please provide your recommendation and technical justification.
8. The Standard Drafting Team (SDT) is proposing a phased-in implementation plan approach. Do you agree with the proposed phased-in
timeframes? If you do not agree, please provide your recommendation and technical justification.
9. Provide any additional comments for the SDT to consider, including the provided technical rationale document, if desired.

Organization
Name

Name

BC Hydro and Adrian
Power
Andreoiu
Authority

Segment(s)

1

Adrian Harris Adrian Harris

Santee
Cooper

Chris
Wagner

Southern
Colby
Company Galloway
Southern
Company
Services, Inc.

Region

WECC

Group Name Group Member
Name
BC Hydro

RTO/ISO
Council
Standard
Review
Committee
Project 202307 TPL-008

1

1,3,5,6

Santee
Cooper

MRO,RF,SERC,Texas Southern
RE,WECC
Company

Group
Group
Member
Member
Organization Segment(s)

Group
Member
Region

Hootan Jarollahi BC Hydro and 3
Power
Authority

WECC

Helen Hamilton
Harding

BC Hydro and 5
Power
Authority

WECC

Adrian Andreoiu BC Hydro and 1
Power
Authority

WECC

Elizabeth Davis

PJM

2

RF

Gregory
Campoli

New York
Independent
System
Operator

2

NPCC

Adrian Harris

MISO

2

RF

Helen Lainis

Independent
Electricity
System
Operator

2

NPCC

Charles Yeung

SPP

2

MRO

Chris Wagner

Santee
Cooper

1,3,5,6

SERC

Weijian Cong

Santee
Cooper

1,3,5,6

SERC

Rene' Free

Santee
Cooper

1,3,5,6

SERC

Matt Carden

Southern
1
Company Southern
Company
Services, Inc.

SERC

Joel Dembowski Southern
Company Alabama
Power
Company

3

SERC

Ron Carlsen

6

SERC

Southern
Company Southern
Company
Generation

Eversource
Energy

Public Utility
District No. 1
of Chelan
County

FirstEnergy FirstEnergy
Corporation

Joshua
London

Joyce
Gundry

Mark Garza

1

3

4

Eversource

CHPD

FE Voter

Leslie Burke

Southern
Company Southern
Company
Generation

5

SERC

Joshua London

Eversource
Energy

1

NPCC

Vicki O'Leary

Eversource
Energy

3

NPCC

Rebecca Zahler Public Utility
District No. 1
of Chelan
County

5

WECC

Tamarra Hardie Public Utility
District No. 1
of Chelan
County

6

WECC

Joyce Gundry

Public Utility
District No. 1
of Chelan
County

3

WECC

Diane Landry

Public Utility
District No. 1
of Chelan
County

1

WECC

Julie Severino

FirstEnergy FirstEnergy
Corporation

1

RF

Aaron
Ghodooshim

FirstEnergy FirstEnergy
Corporation

3

RF

Robert Loy

FirstEnergy FirstEnergy
Solutions

5

RF

Mark Garza

FirstEnergyFirstEnergy

1,3,4,5,6

RF

6

RF

Stacey Sheehan FirstEnergy FirstEnergy
Corporation
Northern
California
Power
Agency

Michael
Whitney

3

NCPA

Scott
Tomashefsky

Northern
4
California
Power Agency

WECC

Marty Hostler

Northern
5,6
California
Power Agency

WECC

Marty Hostler

Black Hills
Corporation

Northeast
Power
Coordinating
Council

Rachel
Schuldt

Ruida Shu

6

1,2,3,4,5,6,7,8,9,10 NPCC

Northern
5,6
California
Power Agency

WECC

Black Hills
Corporation

1

WECC

Black Hills
Corporation

3

WECC

Rachel Schuldt

Black Hills
Corporation

6

WECC

Carly Miller

Black Hills
Corporation

5

WECC

Sheila
Suurmeier

Black Hills
Corporation

5

WECC

Gerry Dunbar

Northeast
Power
Coordinating
Council

10

NPCC

Deidre Altobell

Con Edison

1

NPCC

Michele Tondalo United
Illuminating
Co.

1

NPCC

Stephanie Ullah- Orange and
Mazzuca
Rockland

1

NPCC

Michael
Ridolfino

Central
Hudson Gas
& Electric
Corp.

1

NPCC

Randy Buswell

Vermont
1
Electric Power
Company

NPCC

James Grant

NYISO

2

NPCC

Dermot Smyth

Con Ed 1
Consolidated
Edison Co. of
New York

NPCC

David Burke

Orange and
Rockland

3

NPCC

Peter Yost

Con Ed 3
Consolidated
Edison Co. of
New York

NPCC

Salvatore
Spagnolo

New York
Power
Authority

NPCC

Black Hills
Micah Runner
Corporation All Segments Josh Combs

NPCC RSC

1

Sean Bodkin

Dominion Dominion
Resources,
Inc.

6

NPCC

David Kwan

Ontario Power 4
Generation

NPCC

Silvia Mitchell

NextEra
1
Energy Florida Power
and Light Co.

NPCC

Sean Cavote

PSEG

4

NPCC

Jason Chandler Con Edison

5

NPCC

Tracy MacNicoll Utility
Services

5

NPCC

Shivaz Chopra

New York
Power
Authority

6

NPCC

Vijay Puran

New York
6
State
Department of
Public Service

NPCC

David Kiguel

Independent

7

NPCC

Joel Charlebois

AESI

7

NPCC

Joshua London

Eversource
Energy

1

NPCC

Emma Halilovic

Hydro One
1,2
Networks, Inc.

NPCC

Emma Halilovic

Hydro One
1,2
Networks, Inc.

NPCC

Chantal Mazza

Hydro Quebec 1,2

NPCC

Emma Halilovic

Hydro One
1,2
Networks, Inc.

NPCC

Chantal Mazza

Hydro Quebec 1,2

NPCC

Nicolas Turcotte Hydro1
Quebec (HQ)

NPCC

Jeffrey Streifling NB Power
Corporation

1,4,10

NPCC

Jeffrey Streifling NB Power
Corporation

1,4,10

NPCC

Jeffrey Streifling NB Power
Corporation

1,4,10

NPCC

Joel Charlebois

7

NPCC

AESI

Dominion Dominion
Resources,
Inc.

Southwest
Power Pool,
Inc. (RTO)

Sean Bodkin 6

Shannon
Mickens

2

Dominion

MRO,SPP RE,WECC SPP RTO

Connie Lowe

Dominion Dominion
Resources,
Inc.

3

NA - Not
Applicable

Lou Oberski

Dominion Dominion
Resources,
Inc.

5

NA - Not
Applicable

Larry Nash

Dominion 1
Dominion
Virginia Power

NA - Not
Applicable

Rachel Snead

Dominion Dominion
Resources,
Inc.

5

NA - Not
Applicable

Shannon
Mickens

Southwest
Power Pool
Inc.

2

MRO

Mia Wilson

Southwest
Power Pool
Inc.

2

MRO

Josh Phillips

Southwest
Power Pool
Inc.

2

MRO

Eddie Watson

Southwest
Power Pool
Inc.

2

MRO

Jim William

Southwest
Power Pool
Inc.

2

MRO

Jeff McDiarmid

Southwest
Power Pool
Inc.

2

MRO

Mason Favazza Southwest
Power Pool
Inc.

2

MRO

Jonathan Hayes Southwest
Power Pool
Inc.

2

MRO

Scott Jordan

Southwest
Power Pool
Inc.

2

MRO

Dee Edmondson Southwest
Power Pool
Inc.

2

MRO

Stephen
Whaite

Stephen
Whaite

Western
Electricity
Coordinating
Council

Steven
Rueckert

Tim Kelley

Tim Kelley

Associated
Electric
Cooperative,
Inc.

Todd
Bennett

RF

10

3

Southwest
Power Pool
Inc.

2

MRO

Lottie Jones

Southwest
Power Pool
Inc.

2

MRO

Nathan Bean

Southwest
Power Pool
Inc

2

MRO

ReliabilityFirst Lindsey
ReliabilityFirst 10
Ballot Body
Mannion
Member and Stephen Whaite ReliabilityFirst 10
Proxies
Tyler
ReliabilityFirst 10
Schwendiman
WECC

WECC

Sherri Maxey

SMUD and
BANC

AECI

RF
RF
RF

Greg Sorenson

ReliabilityFirst 10

RF

Steve Rueckert

WECC

10

WECC

Curtis Crews

WECC

10

WECC

Nicole Looney

Sacramento
Municipal
Utility District

3

WECC

Charles Norton

Sacramento
Municipal
Utility District

6

WECC

Wei Shao

Sacramento
Municipal
Utility District

1

WECC

Foung Mua

Sacramento
Municipal
Utility District

4

WECC

Nicole Goi

Sacramento
Municipal
Utility District

5

WECC

Kevin Smith

Balancing
Authority of
Northern
California

1

WECC

Michael Bax

Central
1
Electric Power
Cooperative
(Missouri)

SERC

Adam Weber

Central
3
Electric Power
Cooperative
(Missouri)

SERC

Gary Dollins

M and A
3
Electric Power
Cooperative

SERC

William Price

M and A
1
Electric Power
Cooperative

SERC

Olivia Olson

Sho-Me
1
Power Electric
Cooperative

SERC

Mark Ramsey

N.W. Electric
Power
Cooperative,
Inc.

1

SERC

Heath Henry

NW Electric
Power
Cooperative,
Inc.

3

SERC

Tony Gott

KAMO
Electric
Cooperative

3

SERC

Micah Breedlove KAMO
Electric
Cooperative

1

SERC

Brett Douglas

Northeast
1
Missouri
Electric Power
Cooperative

SERC

Skyler
Wiegmann

Northeast
3
Missouri
Electric Power
Cooperative

SERC

Mark Riley

Associated
Electric
Cooperative,
Inc.

1

SERC

Brian
Ackermann

Associated
Electric
Cooperative,
Inc.

6

SERC

Chuck Booth

Associated
Electric
Cooperative,
Inc.

5

SERC

Jarrod
Murdaugh

Sho-Me
3
Power Electric
Cooperative

SERC

1. Do you agree with the proposed definition of Extreme Temperature Assessment? If you do not agree, please provide your recommendation
and, if appropriate, technical justification.
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

No

Document Name
Comment
The definition appears to be in the same line as Extreme Cold Weather Temperature (ECWT) which is assessing extreme temperatures based on
historic data. Extreme Temperature Assessment sounds like it similarly assesses extreme temperature, but it is an assessment of transmission system
performance during extreme temperatures. Perhaps Extreme Temperature Transmission Assessment (ETTA) would be a better title?
Another point of possible clarification is what is the expected de-minimis scope of this assessment? For example, TPL-008 requires voltage and stability
criteria be documented, but it’s not clear if this is required to be part of the assessment or may 'live outside' the assessment. Similar for CAPs, are
CAPS required to be in the assessment, or may they “live outside” the assessment?
Likes

1

Dislikes

Lakeland Electric, 1, Watt Larry
0

Response
Robert Follini - Avista - Avista Corporation - 3
Answer

No

Document Name
Comment
Extreme temperature needs to be defined.
Likes

0

Dislikes

0

Response
Ben Hammer - Western Area Power Administration - 1
Answer
Document Name
Comment

No

More information regarding “benchmark events” is requested prior to approving the definition.
Likes

0

Dislikes

0

Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer

No

Document Name
Comment
Consumers Energy agrees with CHPD comment:
The definition appears to be in the same line as Extreme Cold Weather Temperature (ECWT) which is assessing extreme temperatures based on
historic data. Extreme Temperature Assessment sounds like it similarly assesses extreme temperature, but it is an assessment of transmission system
performance during extreme temperatures. Perhaps Extreme Temperature Transmission Assessment (ETTA) would be a better title?
Likes

0

Dislikes

0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CEHE has identified a few issues related to the ERO library. First, there is little clarity in the standard that details exactly what the library will contain,
how it will get populated, or which forms of data will be kept. Second, there is no requirement that authorizes the upkeep and ongoing maintenance of
said library. Third, using one extreme heat benchmark, and one extreme cold benchmark, as approved by the ERO, ignores local extreme temperature
events, and may exclude entities who may experience micro weather events. Extreme Temperature Assessments should include regional and
significant local events. It is not clear who in the ERO approves and maintains a library of benchmarked events, or how this process is done for
transparency. It is difficult to support or offer suggested edits to the proposed language if the ERO has not provided the library and defined “Extreme
Temperature Assessment” criteria or defined benchmark event criteria. CEHE would like clarification on the benchmark events, and further clarification
on criteria to determine this responsibility. The approved library of benchmark events is currently not available to the Transmission Planners (TPs),
therefore, CEHE cannot support any of the proposed requirements as written.
Likes

0

Dislikes
Response

0

Leslie Hamby - Southern Indiana Gas and Electric Co. - 3,5,6 - RF
Answer

No

Document Name
Comment
Southern Indiana Gas & Electric Company d/b/a CenterPoint Energy Indiana South (SIGE) does not support the current definition for Extreme
Temperature Assessment without a better understanding of the ‘benchmark events’ and ‘benchmark library’. SIGE is unable to fully evaluate the
definition at this time. During the recent Project 2023-07 Industry Webinar, the Drafting Team stated examples should be available by the July posting
(Draft 2). After reviewing the examples, SIGE will provide more definitive feedback.
Likes

0

Dislikes

0

Response
Apollonia Gonzales - PNM Resources - 1,3 - WECC,Texas RE
Answer

No

Document Name
Comment
PNMR agrees with EEI's comments in not supporting the proposed definition.
Likes

0

Dislikes

0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

No

Document Name
Comment
For this initial ballot, it is difficult to fully agree with the proposed definition without knowing what “benchmark events” are.
Likes
Dislikes

0
0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

No

Document Name
Comment
Too general. What is included in the assessment? Steady State? Transient Stability?
Likes

0

Dislikes

0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

No

Document Name
Comment
Minnesota Power supports MRO’s NERC Standards Review Forum’s (NSRF) comments.
Likes

0

Dislikes

0

Response
Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer

No

Document Name
Comment
MPC supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
Likes

0

Dislikes
Response

0

Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst Ballot
Body Member and Proxies
Answer

No

Document Name
Comment
RF is concerned that “extreme heat and extreme cold temperature” is left undefined. RF recommends the definition include defined thresholds that can
be easily measured.
Likes

0

Dislikes

0

Response
Michele Tondalo - United Illuminating Co. - 1
Answer

No

Document Name
Comment
There is an inconsistency between the proposed definition of an “Extreme Temperature Assessment” and the existing definition of a “Planning
Assessment”; specifically, the Planning Assessment definition includes indication of Corrective Action Plans to remedy identified deficiencies.
Likes

0

Dislikes

0

Response
Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

No

Document Name
Comment
There is an inconsistency between the proposed definition of an “Extreme Temperature Assessment” and the existing definition of a “Planning
Assessment”; specifically, the Planning Assessment definition includes indication of Corrective Action Plans to remedy identified deficiencies.
Likes

0

Dislikes
Response

0

Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
The following recommended wording addition attempts to incorporate references to the approximation that is typically part of an assessment and type of
analysis the assessment is based on.
“Documented evaluation or estimation of future Transmission System performance for specified contingencies and electric scenarios applicable to
extreme heat and extreme cold temperature benchmark events.”
Likes

0

Dislikes

0

Response
Brittany Millard - Lincoln Electric System - 5
Answer

No

Document Name
Comment
LES supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
Likes

0

Dislikes

0

Response
Katrina Lyons - Georgia System Operations Corporation - 4
Answer

No

Document Name
Comment
GSOC supports Georgia Transmission Corporation's comments:
The following recommended wording addition attempts to incorporate references to the approximation that is typically part of an assessment and type of
analysis the assessment is based on.
“Documented evaluation or estimation of future Transmission System performance for specified contingencies and electric scenarios applicable to
extreme heat and extreme cold temperature benchmark events.”

Likes

0

Dislikes

0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
Do not agree that you can evaluate future performance. Suggested edit is “documentation of expected performance during future Transmission System
extreme heat and extreme cold temperature benchmark events.”
Likes

0

Dislikes

0

Response
Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer

No

Document Name
Comment
AECI supports comment provided by Georgia Transmission Corporation
Likes

0

Dislikes

0

Response
Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer

No

Document Name
Comment

While the definition seems appropriate, ISO-NE reserves its determination until a complete list of the “benchmark events” is made
available.
Likes

0

Dislikes

0

Response
David Jendras Sr - Ameren - Ameren Services - 3
Answer

No

Document Name
Comment
Ameren suggests removing the word "documented" from the definition.
Likes

0

Dislikes

0

Response
Colby Galloway - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment
Southern Company seeks clarification to benchmark events.
Likes

0

Dislikes

0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

No

Document Name
Comment
Although the wording is fine, the definition is inconsistent with “extreme weather,” there is no definition of extreme weather – rather, the proposed
standard alludes to benchmark events. Since such extreme weather events could vary geographically, it is recommended that the drafting team add in
language ensuring that regional variances be recognized. Adding this would resolve the discrepancy in using the term “extreme weather”. Except if
there is a possibility of extending TPL-008 to other weather/natural emergencies, NERC TPL-008 documents should clarify that the standard is to only
address temperature extremes.

Likes

0

Dislikes

0

Response
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

No

Document Name
Comment
NIPSCO is unable to support the current definition without more information that provides a better understanding of “benchmark events” and
“benchmark library”. NIPSCO further agrees that clarity would be brought to the current definition if it included defined and measurable thresholds for
“extreme heat and extreme cold temperature”, and that adding transmission to the title would also bring clarity since it is an assessment of transmission
system performance during extreme temperatures.
Likes

0

Dislikes

0

Response
Amy Wilke - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
ATC generally supports the MRO NSRF comments.
Likes

0

Dislikes

0

Response
Wayne Guttormson - SaskPower - 1
Answer
Document Name
Comment
Support the MRO NSRF comments.

No

Likes

0

Dislikes

0

Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO,WECC, Group Name SPP RTO
Answer

No

Document Name
Comment
SPP has concerns that the term “extreme” does not truly define the expectations of the assessment. For example, there could be a 100-degree day with
no major events. However, there could be a week where the temperature was 90 degrees, and you have an extreme event happen during that
timeframe. The initial assumption would be that the term “extreme” aligns better with the 100-dgree scenario; however, the actual event took place in
the 90-degree temperature range.
Furthermore, there is a concern that a forced generator outage could be impacted by other factors besides temperature. At this point, the question
would be are those other factors considered criteria that support the expectation of the term “extreme event”?
SPP recommends that the drafting team provide clarity on the expectation on the term “extreme event”. Also, we recommend the drafting team consider
developing some type of checklist to help them structure criteria to define an “extreme event. “
Likes

0

Dislikes

0

Response
Adrian Harris - Adrian Harris On Behalf of: Bobbi Welch, Midcontinent ISO, Inc., 2; - Adrian Harris, Group Name RTO/ISO Council Standard
Review Committee Project 2023-07 TPL-008
Answer

No

Document Name
Comment
Q1. Conceptually, the proposed definition for Extreme Temperature Assessment does not presently appear to present any issues; however, the
ISO/RTO Council Standards Review Committee (SRC) is unable to fully evaluate the definition without more information regarding the “benchmark
events” that will be key to performing Extreme Temperature Assessments.
Our understanding is that NERC intends to post sample benchmark event(s) on or around July 9, 2024. The SRC will be able to provide more definitive
feedback once this information is available.
___________________________________________________________________________________
Extreme Temperature Assessment – Documented evaluation of future Transmission System performance for extreme heat and extreme cold
temperature benchmark events.

Planning Assessment - Documented evaluation of future Transmission System performance and Corrective Action Plans to remedy identified
deficiencies.
Likes

0

Dislikes

0

Response
Catrina Martin - Archer Energy Solutions, LLC - 5
Answer

No

Document Name
Comment
The current definition focuses on temperature, but in other NERC documents the focus is on “extreme weather.” Since extreme weather events could
be a broader topic (e.g., hurricanes, ice storms, blizzards, wind storms, wildfires), it would be helpful for all NERC documents to be clear that we are
only addressing extreme temperature with TPL-008, unless we want to expand the scope of TPL-008 to include other weather disasters. More severe
weather events would typically be addressed in the planning horizon by extreme events studied under TPL-001 or in real time with emergency operating
plans and restoration plans. As a result, extreme weather events are already addressed by other standards.
The definition also relies on the phrase “extreme heat and extreme cold temperature benchmark events,” which are not defined. TPL-007, which is
similar to TPL-008, includes Attachment 1 which defines the benchmark GMD event. We recommend that a similar Attachment that describes
benchmark events or definition for Extreme Heat Benchmark Event and Extreme Cold Temperature Benchmark Event be developed. A lack of clarity
on this issue will make it very difficult to get any consistency on a regional or nationwide basis.
Some utilities already study 1-in-10 year load forecasts which include temperature-adjusted loads. In some ways that is a 1-in-10 year heat storm for
summer peaking areas or 1-in-10 year cold snap for winter peaking areas. Of course, that is backward looking, so we might need to include some sort
of adjustment for climate change going forward. All of these issues could be addressed in a benchmark event attachment for TPL-008.
Likes

0

Dislikes

0

Response
Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Entergy questions whether this definition is necessary.
Likes
Dislikes

0
0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

Yes

Document Name
Comment
Black Hills Corporation agrees with EEI and supports the proposed definition for Extreme Temperature Assessment.
Likes

0

Dislikes

0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
Comment
FirstEnergy has no concerns with the proposed term.
Likes

0

Dislikes

0

Response
Lenise Kimes - City and County of San Francisco - 1,5 - WECC
Answer

Yes

Document Name
Comment
While the definition itself is acceptable, there is some conflict with the term “extreme weather” which is in the name of the program itself. Since extreme
weather could be a broader topic (e.g., hurricanes, ice storms, blizzards), it would be helpful for all NERC documents to be clear that we are only
addressing extreme temperature with TPL-008, unless we want to expand the scope of TPL-008 to include other weather disasters. More severe
events would typically be addressed with emergency operating plans.
Likes
Dislikes

1

Lakeland Electric, 1, Watt Larry
0

Response
Kristine Martz - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI supports the proposed definition for Extreme Temperature Assessment.
Likes

0

Dislikes

0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
None.
Likes

0

Dislikes

0

Response
Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer

Yes

Document Name
Comment
Further clarity needed on the NERC developed benchmark events and library.
Likes

0

Dislikes
Response

0

Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

Yes

Document Name
Comment
ITC supports the definition of Extreme Temperature Assessment. Did the team consider an Extreme Weather Assessment rather than ETA? ITC also is
looking for additional information on the benchmark events.
Likes

0

Dislikes

0

Response
Robert Jones - Seattle City Light - 1,3,4,6
Answer

Yes

Document Name
Comment
The definition of Extreme Temperature Assessment is vague. Each utility’s understanding of the extreme temperature can be different and guidance to
define extreme temperature criteria and what to study should be provided in the standard. Perhaps, TPL-001 should cover extreme temperature
assessment.
Likes

0

Dislikes

0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

Yes

Document Name
Comment
“See comments submitted by the Edison Electric Institute”
Likes

0

Dislikes
Response

0

Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the proposed definition for Extreme Temperature Assessment.
Likes

0

Dislikes

0

Response
Kinte Whitehead - Exelon - 3
Answer

Yes

Document Name
Comment
Exelon supports the proposed definition for Extreme Temperature Assessment.
Likes

0

Dislikes

0

Response
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment
NV Energy supports the proposed definition for Extreme Temperature Assessment.
Likes

0

Dislikes

0

Response
Kevin Conway - Western Power Pool - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1 - WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Lauren Giordano - Lauren Giordano On Behalf of: Dennis Sismaet, Northern California Power Agency, 4, 6, 3, 5; Marty Hostler, Northern
California Power Agency, 4, 6, 3, 5; Michael Whitney, Northern California Power Agency, 4, 6, 3, 5; - Lauren Giordano
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Michael Whitney - Northern California Power Agency - 3, Group Name NCPA
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Isidoro Behar - Long Island Power Authority - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Mark Flanary - Midwest Reliability Organization - 10
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

Response
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Israel Perez - Israel Perez On Behalf of: Mathew Weber, Salt River Project, 3, 1, 6, 5; Matthew Jaramilla, Salt River Project, 3, 1, 6, 5; Thomas
Johnson, Salt River Project, 3, 1, 6, 5; Timothy Singh, Salt River Project, 3, 1, 6, 5; - Israel Perez
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Richard Vendetti - NextEra Energy - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza
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
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Junji Yamaguchi - Hydro-Quebec (HQ) - 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 NPCC RSC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
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
Kimberly Turco - Constellation - 6
Answer
Document Name

Comment
Constellation has no comments
Kimberly Turco on behalf of Constellation Segments 5 and 6
Likes

0

Dislikes

0

Response
Alison MacKellar - Constellation - 5
Answer
Document Name
Comment
Constellation has no comments
Alison Mackellar on behalf of Constellation Segments 5 and 6
Likes

0

Dislikes

0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Given the range of temperatures across the United States, Texas RE recommends the following revisions to the definition of Extreme Temperature
Assessment (in bold):
Documented evaluation of future Transmission System performance for extreme heat and extreme cold temperature benchmark events based on the
geographical location.
Likes

0

Dislikes
Response

0

2. Do you agree with the proposed TPL-008-1 Reliability Standard Requirement R1? If you do not agree, please provide your recommendation
and, if appropriate, technical justification.
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

No

Document Name
Comment
NIPSCO supports the comments provided by BPA, CMS Energy, CHPD, and TVA.
Likes

0

Dislikes

0

Response
David Jendras Sr - Ameren - Ameren Services - 3
Answer

No

Document Name
Comment
Ameren believes it should be clearer who is responsible for performing the Extreme Temperature Assessment. R1 should determine specific roles for
both the PC and TP.
Likes

0

Dislikes

0

Response
Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer

No

Document Name
Comment
AECI supports comment provided by Georgia Transmission Corporation
Likes

0

Dislikes
Response

0

Katrina Lyons - Georgia System Operations Corporation - 4
Answer

No

Document Name
Comment
GSOC supports Georgia Transmission Corporation's comments::
The following wording suggestion adds modeling responsibilities to the requirement.
“Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall determine and identify each entity’s individual and joint
responsibilities for maintaining models and performing the studies needed to complete the Extreme Temperature Assessment.”
Likes

0

Dislikes

0

Response
Brittany Millard - Lincoln Electric System - 5
Answer

No

Document Name
Comment
LES supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
Likes

0

Dislikes

0

Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
The following wording suggestion adds modeling responsibilities to the requirement.
“Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall determine and identify each entity’s individual and joint
responsibilities for maintaining models and performing the studies needed to complete the Extreme Temperature Assessment.”
Likes

0

Dislikes

0

Response
Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

No

Document Name
Comment
The wording used in TPL-008-1 R1 calls out defining responsibilities for “…performing studies…” which is similar to TPL-007; but it is not clear if TPL008 assumes that each of the subsequent Requirements that state “Each responsible entity, as identified in Requirement R1…” are considered part of
study performance, developing the assessment, or a separate preparation activity. Suggest wording in R1 be changed to “…shall determine and identify
each entity’s individual and joint responsibilities for performing the necessary studies and development of the Extreme Temperature Assessment(s)…”
Likes

0

Dislikes

0

Response
Michele Tondalo - United Illuminating Co. - 1
Answer

No

Document Name
Comment
The wording used in TPL-008-1 R1 calls out defining responsibilities for “…performing studies…” which is similar to TPL-007; but it is not clear if TPL008 assumes that each of the subsequent Requirements that state “Each responsible entity, as identified in Requirement R1…” are considered part of
study performance, developing the assessment, or a separate preparation activity. Suggest wording in R1 be changed to “…shall determine and identify
each entity’s individual and joint responsibilities for performing the necessary studies and development of the Extreme Temperature Assessment(s)…”
Likes

0

Dislikes

0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

No

Document Name
Comment
Need more clarity on definition of Benchmark event (Last 5 years? Last 30 years?

Likes

0

Dislikes

0

Response
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA recommends extreme benchmark events be evaluated for their impact in a larger region than just the TP/PC area. As such, utilities in the region
need to assess the impact on the region. BPA recommends the Regional Entities perform these assessments in collaboration with the utilities in the
region, this would help ensure utilities are better suited to consider mitigation actions in their system. Footprints of the benchmark events should be
defined by the Regional Entity and consider the electrical boundaries. Coordination should be done with the responsible entities (adjacent PCs and
TPs) within that footprint, as well as the Regional Entity.
Likes

1

Dislikes

Lakeland Electric, 1, Watt Larry
0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
Please refer to Question 1 comments.
Likes

0

Dislikes

0

Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer

No

Document Name
Comment
Consumers Energy Agrees with the comments by WPP:

R1 reads as if the Planning Coordinator is solely responsible for compliance to this Requirement. "...in conjunction with its Transmission
Planners(s)...implies that the transmission planners are passive participants and are not responsible for compliance. If this was not the intent of the
drafting team, then this should more clearly state that the "Planning Coordinators and associated Transmission Planner(s) shall coordinate each entity’s
individual and joint responsibilities..."
Likes

0

Dislikes

0

Response
Michael Whitney - Northern California Power Agency - 3, Group Name NCPA
Answer

No

Document Name
Comment
NO, These assessment should be performed by the Regional Entities. There appears to be too much room for coordination issues having one
Transmission Planner (TP) or Planning Coordinator (PC) having to rely on other TPs or PCs to meet their requirement deadlines.
Likes

0

Dislikes

0

Response
Lauren Giordano - Lauren Giordano On Behalf of: Dennis Sismaet, Northern California Power Agency, 4, 6, 3, 5; Marty Hostler, Northern
California Power Agency, 4, 6, 3, 5; Michael Whitney, Northern California Power Agency, 4, 6, 3, 5; - Lauren Giordano
Answer

No

Document Name
Comment
NO, These assessment should be performed by the Regional Entities. There appears to be too much room for coordination issues having one
Transmission Planner (TP) or Planning Coordinator (PC) having to rely on other TPs or PCs to meet their requirement deadlines.
Likes

1

Dislikes

Lakeland Electric, 1, Watt Larry
0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1 - WECC
Answer
Document Name

No

Comment
Leads to double jeopardy since this language is included in TPL-001-5.1 and TPL-007-4. No problem if the requirement was only in a single standard.

Likes

0

Dislikes

0

Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
It does not seem appropriate to agree to a requirement that has yet to be fully developed. Based on the technical rationale, there is an expectation that
the ERO will determine suitability and make available benchmark events representative of probable futures. Once the initial library of events have been
developed, we would be in a better position to consider support for this requirement.
Likes

0

Dislikes

0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

No

Document Name
Comment
The term ‘the studies’ is somewhat vague. The studies themselves are expected to be steady state and stability (FERC Order 896 uses ‘transient
stability’, as the preferred descriptor to clarify from other types of stability), but the compliance reader does not discover this until R8. The effort may
also include the building of cases (R3) based on the R2 benchmark events, but these are not themselves study activities, but rather case-build activities.
R1 likely should address performing the study (R8) and case build activities (R2, R3).
In conclusion, the term ‘the studies’ is vague, and it turns out possibly misleading. Assigned duties are much greater in scope. An alternate approach
could be “Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall determine and identify each entity’s individual and joint
responsibilities for performing the steady state and stability studies and activities needed to complete the Extreme Temperature Assessment”. The
existing language at the end of the R1, “needed to complete the Extreme Temperature Assessment” finishes the thought adequately (although as noted
in the comment #1, the scope of ETA should be clarified).
Likes

1

Lakeland Electric, 1, Watt Larry

Dislikes

0

Response
Kevin Conway - Western Power Pool - 4
Answer

No

Document Name
Comment
R1 reads as if the Planning Coordinator is solely responsible for compliance to this Requirement. "...in conjunction with its Transmission
Planners(s)...implies that the transmission planners are passive participants and are not responsible for compliance. If this was not the intent of the
drafting team, then this should more clearly state that the "Planning Coordinators and associated Transmission Planner(s) shall coordinate each entity’s
individual and joint responsibilities..."
Alternatively, the Planning Coordinator can simply assign the responsibilities, and a new requirement for Transmission Planners would require them to
perform studies as specified by the Planning Coordinator.
Likes

1

Dislikes

Lakeland Electric, 1, Watt Larry
0

Response
Apollonia Gonzales - PNM Resources - 1,3 - WECC,Texas RE
Answer

No

Document Name
Comment
Likes

0

Dislikes

0

Response
Catrina Martin - Archer Energy Solutions, LLC - 5
Answer

Yes

Document Name
Comment
While the wording on R1 is consistent with TPL-001, there are some concerns about negotiating the workload impacts of additional studies between the
PC and TP entities. As additional responsibilities are added for PC and TP entities, this negotiation becomes increasingly difficult. The level of detail

and periodicity of TPL-008 studies will further increase the workload on already overstressed entities. The human resources requirements for TPL-008
should be considered when setting the requirements.
Likes

0

Dislikes

0

Response
Adrian Harris - Adrian Harris On Behalf of: Bobbi Welch, Midcontinent ISO, Inc., 2; - Adrian Harris, Group Name RTO/ISO Council Standard
Review Committee Project 2023-07 TPL-008
Answer

Yes

Document Name
Comment
The SRC supports modeling proposed TPL-008, requirement R1 after TPL-001-5.1, requirement R7 and TPL-007, requirement R1.
Likes

0

Dislikes

0

Response
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment
NV Energy does not have any objections to the proposed language for Requirement R1.
Likes

0

Dislikes

0

Response
Wayne Guttormson - SaskPower - 1
Answer
Document Name
Comment
Support the MRO NSRF comments.

Yes

Likes

0

Dislikes

0

Response
Kinte Whitehead - Exelon - 3
Answer

Yes

Document Name
Comment
Exelon does not have any objections to the proposed language for Requirement R1.
Likes

0

Dislikes

0

Response
Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon does not have any objections to the proposed language for Requirement R1.
Likes

0

Dislikes

0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

Yes

Document Name
Comment
“See comments submitted by the Edison Electric Institute”
Likes
Dislikes

0
0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

Yes

Document Name
Comment
ITC supports modeling proposed TPL-008, requirement R1 after TPL-001-5.1, requirement R7 and TPL-007, requirement R1.
Likes

0

Dislikes

0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

Yes

Document Name
Comment
The proposed TPL-008-1 Reliability Standard Requirement R1 seems to be an extension of TPL-001-5, however, it will require for each responsible
entities to ramp up the workforce to conduct these studies, analyze the events and develop CAPs. Hence, human resources need is a crucial element to
consider while creating requirements for TPL-008.
Likes

0

Dislikes

0

Response
Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer

Yes

Document Name
Comment

No Additional Comments
Likes
Dislikes

0
0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
None.
Likes

0

Dislikes

0

Response
Kristine Martz - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI does not have any objections to the proposed language for Requirement R1.
Likes

0

Dislikes

0

Response
Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer

Yes

Document Name
Comment
MPC supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
Likes

0

Dislikes
Response

0

Lenise Kimes - City and County of San Francisco - 1,5 - WECC
Answer

Yes

Document Name
Comment
While the wording on R1 is consistent with TPL-001, there are some concerns about negotiating the workload impacts of additional studies between the
PC and TP entities. As additional responsibilities are added for PC and TP entities, this negotiation becomes increasingly difficult. The level of detail
and periodicity of TPL-008 studies will further increase the workload on already overstressed entities. The human resources requirements for TPL-008
should be considered when setting the requirements.
Likes

0

Dislikes

0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
Comment
No additional comment.
Likes

0

Dislikes

0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

Yes

Document Name
Comment
Black Hills Corporation agrees with EEI and does not have any objections to the proposed language for Requirement R1.
Likes

0

Dislikes
Response

0

Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO,WECC, Group Name SPP RTO
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 NPCC RSC
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Amy Wilke - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Robert Jones - Seattle City Light - 1,3,4,6
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Colby Galloway - 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
Junji Yamaguchi - Hydro-Quebec (HQ) - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 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
Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Richard Vendetti - NextEra Energy - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst Ballot
Body Member and Proxies
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Joshua London - Eversource Energy - 1, Group Name Eversource
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Israel Perez - Israel Perez On Behalf of: Mathew Weber, Salt River Project, 3, 1, 6, 5; Matthew Jaramilla, Salt River Project, 3, 1, 6, 5; Thomas
Johnson, Salt River Project, 3, 1, 6, 5; Timothy Singh, Salt River Project, 3, 1, 6, 5; - Israel Perez
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

Yes

Document Name
Comment
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0

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0

Response
Leslie Hamby - Southern Indiana Gas and Electric Co. - 3,5,6 - RF
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Mark Flanary - Midwest Reliability Organization - 10
Answer

Yes

Document Name
Comment
Likes

0

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Response

0

Isidoro Behar - Long Island Power Authority - 1
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Ben Hammer - Western Area Power Administration - 1
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Robert Follini - Avista - Avista Corporation - 3
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Document Name
Comment

Yes

Likes

0

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0

Response
Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
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0

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0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC

Answer

Yes

Document Name
Comment
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0

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0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE recommends the PC and TP have a formal agreement defining each individual and joint responsibilities for their respective areas. Texas RE
suggests the following additional language (in bold):

R1. Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall determine and identify each entity’s individual and joint
responsibilities for performing the studies needed to complete the Extreme Temperature Assessment within its respective area.

Regarding Measure M1, Texas RE posits that while meeting minutes may help support compliance for Requirement R1, meeting minutes alone would
not constitute proper evidence of compliance with Requirement R1. Texas RE recommends removing meeting minutes from Measure M1.
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0

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0

Response
Alison MacKellar - Constellation - 5
Answer
Document Name
Comment
Constellation has no comments
Alison Mackellar on behalf of Constellation Segments 5 and 6
Likes

0

Dislikes

0

Response
Kimberly Turco - Constellation - 6
Answer
Document Name
Comment
Constellation has no comments
Kimberly Turco on behalf of Constellation Segments 5 and 6
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0

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0

3. Do you agree with the proposed TPL-008-1 Reliability Standard Requirement R2 (Benchmark events)? If you do not agree, please provide
your recommendation and, if appropriate, technical or procedural justification.
Kevin Conway - Western Power Pool - 4
Answer

No

Document Name
Comment
As R1 currently reads, only the Planning Coordinator is responsible for compliance.
Assuming that the Drafting Team would like to hold the Transmission Planner(s) accountable, this should be specifically called out.
The ERO library creates consternation for utilities. There is little clarity in the standard that details exactly what the library will contain, how it will get
populated, or which forms of data will be kept. There is no requirement that authorizes the upkeep and ongoing maintenance of said library.
Using one extreme heat benchmark, and one extreme cold benchmark, as approved by the ERO, ignores local extreme temperature events and may
exclude entities who are geographic regions who may experience micro weather climates. Extreme Temperature Assessments should include regional
and significant local events. It is not clear who in the ERO approves and maintains a library of benchmarked events, or how this process is done for
transparency.
Likes

0

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0

Response
Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
Entergy believes R2 seems to bypass the idea that standards requirements go through the usual process of development and approval. It lets NERC
arbitrarily change the benchmark events library. With the scale of the work required in this standard, it seems similar to having TPL-001-5 Table 1 be a
document on NERC’s website that they can change at will. I would far prefer to see the standard require that the event library be developed/maintained
by (at least) the PCs and regions in collaboration with NERC rather than have it something entirely under NERC’s control.
Likes

1

Dislikes

Lakeland Electric, 1, Watt Larry
0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

No

Document Name
Comment
It is not clear what data the ERO will be using and who will be approving/maintaining the library. Is there a process in place for how this will be
accomplished?
Likes

1

Dislikes

Lakeland Electric, 1, Watt Larry
0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer

No

Document Name
Comment
Should there be any requirements for developing and maintaining benchmark libraries (in co-operation with EROs), or if that is mandated through
another means?
Likes

0

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0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

No

Document Name
Comment
There is a possible gap as it doesn’t appear the ERO is required to maintain a benchmark library, or requirements to determine what this process
should look like. We do not see a mechanism to compel the ERO to sufficiently develop and maintain this benchmark library in an ongoing manner. This
may be a better activity suited for regional entities (RE) with input from Reliability Coordinators (RCs), and regional stakeholders to ensure useful and
meaningful scenarios at a more local level. An alternate approach could be to allow the PC to either select an ERO event or select one of their own
choosing, with a provided technical rationale. Our concern is the ERO process is very high level, and to get the required level of attention for appropriate
events will likely not produce meaningful events for each region.
Likes

1

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Response

Lakeland Electric, 1, Watt Larry
0

Thomas Foltz - AEP - 5
Answer

No

Document Name
Comment
While AEP agrees with the substance of R2, we would like to recommend that the phrase “or more” be added to the requirement so that it instead states
“shall select one *or more* extreme heat benchmark event(s) and one *or more* extreme cold benchmark event(s).”
Regarding the phrase “each responsible entity”, our understanding is that only one entity will be responsible for selecting the benchmark. The SDT may
wish to consider instead using the phrase “the responsible entity established in R1.”
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0

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0

Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
While we might agree with the overall intent to develop a process to coordinate development of a benchmark planning case, implementation is not clear
how individual entities (i.e., “smaller individual planning areas” per the Technical Rationale document) will be able to and responsible for coordinating
scenarios with other impacted parties, such as those outside planning boundaries and when including items such as interchange / transfers.
Additionally, it is not clear what the expectation might be for, and therefore the capability of, modifying cases to include temperature adjustments (if
excessively extreme).
Likes

0

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0

Response
Lauren Giordano - Lauren Giordano On Behalf of: Dennis Sismaet, Northern California Power Agency, 4, 6, 3, 5; Marty Hostler, Northern
California Power Agency, 4, 6, 3, 5; Michael Whitney, Northern California Power Agency, 4, 6, 3, 5; - Lauren Giordano
Answer

No

Document Name
Comment
NO, These assessment should be performed by the Regional Entities. There appears to be too much room for coordination issues having one
Transmission Planner (TP) or Planning Coordinator (PC) having to rely on other TPs or PCs to meet their requirement deadlines.

Likes

0

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0

Response
Michael Whitney - Northern California Power Agency - 3, Group Name NCPA
Answer

No

Document Name
Comment
NO, These assessment should be performed by the Regional Entities. There appears to be too much room for coordination issues having one
Transmission Planner (TP) or Planning Coordinator (PC) having to rely on other TPs or PCs to meet their requirement deadlines.
Likes

0

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0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

No

Document Name
Comment
Black Hills Corporation agrees with EEI’s proposed changes for Requirement R2; requiring the extreme weather events as an attachment to the
standard gives entities visibility into a key part of the new standard and allows for industry review and input.

EEI is concerned that proposed Reliability Standard, TPL-008-1, is being moved forward for industry approval without any insights into a key element of
this Reliability Standard which is the extreme temperature benchmark event library. EEI additionally does not support making this library a separate
document outside of this Reliability Standard. It should be included in the Reliability Standard for industry review or input. This library should be an
attachment within this Reliability Standard, and we offer the following proposed changes to Requirement R2 to address this concern in boldface below:

R2. Each responsible entity, as identified in Requirement R1, shall select one extreme heat benchmark event and one extreme cold benchmark event,
from the Attachment X (remove: approved ERO) (Extreme Temperature Benchmark Library) for performing the Extreme Temperature Assessment.
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
Likes

0

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Response

0

Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

No

Document Name
Comment
Even though Manitoba Hydro supports R2, we are withholding formal support until we can see and evaluate some examples of what the ERO intends to
include as benchmark events in the library.
Likes

0

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0

Response
Robert Follini - Avista - Avista Corporation - 3
Answer

No

Document Name
Comment
Define extreme temperature probability rather than using a historical benchmark.
Likes

0

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0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

No

Document Name
Comment
With lack of intent of what will encompass the benchmark library, FirstEnergy cannot support R2.
For R2, FirstEnergy asks the Drafting Team to determine if the TP would replace “Each responsible entity” for the TB to have sole responsibility for
selecting the benchmark events.
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0

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0

Ben Hammer - Western Area Power Administration - 1
Answer

No

Document Name
Comment
More information on what the ERO intends to include as “benchmark events” is requested prior to approving R2.
Likes

0

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0

Response
Mark Flanary - Midwest Reliability Organization - 10
Answer

No

Document Name
Comment
The draft TPL-008-1 R2 implies an expectation that the ERO will maintain a library of extreme heat and extreme cold events from which responsible
entities will select events. MRO is concerned about potential conflicts if the responsible entities are dependent on ERO in order to be
compliant. Consider modifying R2 by providing an alternative means for entities to comply in a way that is not dependent on the ERO’s maintenance of
a library of events.
Likes

0

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0

Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer

No

Document Name
Comment
Consumers Energy agrees with the comments by WPP:
The ERO library creates consternation for utilities. There is little clarity in the standard that details exactly what the library will contain, how it will get
populated, or which forms of data will be kept. There is no requirement that authorizes the upkeep and ongoing maintenance of said library.
Using one extreme heat benchmark, and one extreme cold benchmark, as approved by the ERO, ignores local extreme temperature events and may
exclude entities who are geographic regions who may experience micro weather climates. Extreme Temperature Assessments should include regional

and significant local events. It is not clear who in the ERO approves and maintains a library of benchmarked events, or how this process is done for
transparency
Likes

0

Dislikes

0

Response
Adrian Andreoiu - BC Hydro and Power Authority - 1, Group Name BC Hydro
Answer

No

Document Name
Comment
BC Hydro appreciates the drafting team efforts and the opportunity to comment.
Requirement R2 indicates that the ERO maintains the “benchmark library” and that this library will need to be approved. The TPL-008-1 Technical
Rationale clarifies that the drafting team is not in a position to provide a statistical basis or determine appropriateness of any specific event and assigns
this responsibility to the ERO.
BC Hydro suggests that it would be appropriate that the ERO develop a process to assess events suitability, which should include criteria for
benchmark event selection. It is also suggested that industry input in the maintenance of the benchmark event library will be beneficial and recommend
that the ERO process accommodate this.
It also seems unclear which information the ERO intends to include for the benchmark events in the library in order to assess the usability in developing
adequate study basecases. Geographical area information should be included and additional Standard provisions for regional variances that allow
flexibility based on regional weather conditions.
Likes

1

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Lakeland Electric, 1, Watt Larry
0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
Please refer to Question 1 comments.
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0

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Response

0

Leslie Hamby - Southern Indiana Gas and Electric Co. - 3,5,6 - RF
Answer

No

Document Name
Comment
Southern Indiana Gas & Electric Company d/b/a CenterPoint Energy Indiana South (SIGE) is unable to fully evaluate Requirement R2 without additional
information about the benchmark event library.
SIGE supports CenterPoint Energy Houston Electric, LLC (CEHE) comment that there is little clarity in the standard that details exactly what the library
will contain, how it will get populated, or which forms of data will be kept. There is no requirement that authorizes the upkeep and ongoing maintenance
of said library. Additionally, it is not clear who in the ERO approves and maintains a library of benchmarked events, or how this process is done for
transparency.
For consideration in developing the benchmark library, SIGE recommends that Planning Coordinators be allowed to submit, extreme heat and cold
events that are impactful to the reliability of the system based on their historical weather events and statistical analysis for inclusion in the library.
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0

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0

Response
Apollonia Gonzales - PNM Resources - 1,3 - WECC,Texas RE
Answer

No

Document Name
Comment
Each responsible entity, as identified in Requirement R1, shall select one extreme heat benchmark event and one extreme cold benchmark event, from
the approved benchmark library that most closely aligns with temperature extremes from past historical events within their region maintained, for
performing the Extreme Temperature Assessment. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
Likes

0

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0

Response
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment

No

BPA recommends that the benchmark events be developed and maintained by the Regional Entities (MRO, NPCC, RF, SECR, Texas RE, and WECC)
as opposed to NERC so that there are applicable events for the region.
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0

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0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

No

Document Name
Comment
Aligning with our comment in Question 1 on the definition of Extreme Temperature Assessment, it is difficult to fully agree with Requirement R2 without
knowing what a “benchmark event” is. The benchmark library needs a methodology that the ERO Enterprise will use as a consistent foundation for
creating the benchmark events.
Likes

0

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0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

No

Document Name
Comment
Put emphasis on Regional, not ERO. Not required for ERO to maintain this library. Such libraries are better maintained at a Regional level. For smaller
utilities, not sure how they are using the same criteria for Extrement Temperature Assessment.
Likes

0

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0

Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer

No

Document Name
Comment
There is not a clear mechanism for the ERO (or the regional entities if delegated) to maintain a library with such information. Also, the size of the library
could be significant as there are 70+ PCs and 200+TPs across the ERO Enterprise. It may be best if NERC undertook the library, but it may be the PC
owning the library for its TPs would be betteer?? Security of such a system would need to be considered as well.
Likes

0

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0

Response
Lenise Kimes - City and County of San Francisco - 1,5 - WECC
Answer

No

Document Name
Comment
Without specifically stating it, the current wording of this requirement puts the responsibility for determining the library of events in the hands of the ERO
and does not explicitly provide the ability for the PC or TP entities to be involved at any point in the development of this library.
If the ERO develops a library of events that are too extreme, this could significantly impact cost of the transmission investment of the PC and TP entities
and ultimately the customers within the PC and TP footprints. If the events are not extreme enough or turn out to be overly severe in one local area or
region and not severe enough in another due to a lack of engagement from regional and local experts, this could also cause distortions in appropriate
planning.
Because the PC and TP entities know their systems (and likely the local climate and weather patterns) better than the ERO, shouldn’t those entities be
at least involved in determining the library of events from which they must select? We suggest that the requirement be reworded to provide the ability
for PCs and TPs to have some control and input for the conditions that are studied for their systems, or even to require the ERO to collaborate with the
PCs and TPs in developing these scenarios, with the ERO having the final decision after considering feedback and comments. There should also be
some guidance provided as to how severe the benchmark cases should be. For example, California’s history of severe weather is very limited and
infrequent due to the tempering effects of the Pacific Ocean, whereas the Midwest (and Texas) is more prone to severe swings in weather and extreme
conditions. Some climate change forecasts predict that this situation may change, but which forecast, if any, should be considered when preparing the
benchmark cases should be at least up for discussion.
Likes

1

Dislikes

Lakeland Electric, 1, Watt Larry
0

Response
Israel Perez - Israel Perez On Behalf of: Mathew Weber, Salt River Project, 3, 1, 6, 5; Matthew Jaramilla, Salt River Project, 3, 1, 6, 5; Thomas
Johnson, Salt River Project, 3, 1, 6, 5; Timothy Singh, Salt River Project, 3, 1, 6, 5; - Israel Perez
Answer
Document Name

No

Comment
SRP agrees and supports JEA's comment that the "approved benchmark library maintained by the Electric Reliability Organization" creates
consternation for utilities due to its ambiguity. We support the idea of The ERO maintaining a library, but there needs to be clarity or some kind of vetting
process with the participation from the industry on the approval process. In addition, SRP strongly recommends separating the extreme heat and
extreme cold scenarios in Requirement R2 to allow entities to perform them separately, but still both to be done every 5 years.
Likes

0

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0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

No

Document Name
Comment
Minnesota Power supports MRO’s NERC Standards Review Forum’s (NSRF) comments.
Likes

0

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0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

No

Document Name
Comment
Oncor would like to ensure transparency in how the benchmark events are developed, chosen, calculated, and maintained. We agree with Entergy’s
comments in that we would like to see the PCs maintain the benchmark event data for the applicable region rather than the data and library being
entirely at one location under NERC control. This approach would likely make the data more transparent and accessible to the affected utilities than
having a sole central repository at NERC for all regions of the country.
Likes

0

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0

Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
Dominion Energy supports EEI comments. In addition, the benchmark cases are not well defined, still being developed, and unclear how they apply to
our Planning Region. This proposed standard is premature and should be delayed until the repository is developed and criteria more clearly established.
Likes

0

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0

Response
Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer

No

Document Name
Comment
MPC supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
Likes

1

Dislikes

Lakeland Electric, 1, Watt Larry
0

Response
Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst Ballot
Body Member and Proxies
Answer

No

Document Name
Comment
RF is concerned that the proposed requirement does not provide any specifications for quantifiable metrics to be used by the PC in identifying
appropriate benchmark events for its region. As written, this requirement may not ensure selected benchmark events for each region will be comparable
in severity and may open the possibility that a PC could select an event that it believes will cause less of an issue in its footprint for ease of study. PCs
in the northern US should choose events to study and establish requirements for Transmission system planning performance for extreme heat and
extreme cold temperature events based upon their geographic location. PC in the southern US should do the same.
Likes

0

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Response

0

Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

No

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and Midwest Reliability Organization's NERC
Standards Review Forum (MRO NSRF) on question 3
Likes

0

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0

Response
Kristine Martz - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment
EEI is concerned that proposed Reliability Standard, TPL-008-1, is being moved forward for industry approval without any insights into a key element of
this Reliability Standard which is the extreme temperature benchmark event library. EEI additionally does not support making this library a separate
document outside of this Reliability Standard. It should be included in the Reliability Standard for industry review or input. This library should be an
attachment within this Reliability Standard and we offer the following proposed changes to Requirement R2 to address this concern in boldface below:
R2. Each responsible entity, as identified in Requirement R1, shall select one extreme heat benchmark event and one extreme cold benchmark event,
from the Attachment X (Extreme Temperature Benchmark Library) for performing the Extreme Temperature Assessment. [Violation Risk Factor: High]
[Time Horizon: Long-term Planning]
Likes

0

Dislikes

0

Response
Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

No

Document Name
Comment
The standard is not clear on the criteria in which the responsible entity can use to select the extreme benchmark events from the benchmark library
maintained by the ERO. There is little information on the events library at this point or how these events are defined and approved.

Likes

0

Dislikes

0

Response
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer

No

Document Name
Comment
LG&E and KU agrees with EEI's comments.
Likes

0

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0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza
Answer

No

Document Name
Comment
•
•

Should there be any requirements for developing and maintaining benchmark libraries (in co-operation with EROs), or if that is mandated
through another means?
“Responsible entity” should be defined in the Applicability section or should replaced with “Each Planning Coordinator, in conjunction with its
Transmission Planner(s)...”Suggest to replace 4.1 to “Responsible Entity” instead of “Functional Entity”.

Likes

0

Dislikes

0

Response
Glen Farmer - Avista - Avista Corporation - 5
Answer

No

Document Name
Comment
EEI is concerned that proposed Reliability Standard, TPL-008-1, is being moved forward for industry approval without any insights into a key element of
this Reliability Standard which is the extreme temperature benchmark event library. EEI additionally does not support making this library a separate

document outside of this Reliability Standard. It should be included in the Reliability Standard for industry review or input. This library should be an
attachment within this Reliability Standard and we offer the following proposed changes to Requirement R2 to address this concern
in boldface below:
R2. Each responsible entity, as identified in Requirement R1, shall select one extreme heat benchmark event and one extreme cold benchmark event,
from the Attachment (Extreme Temperature Benchmark Library) for performing the Extreme Temperature Assessment. [Violation Risk Factor: High]
[Time Horizon: Long-term Planning]

Likes

0

Dislikes

0

Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
It is understood the ERO is tasked with developing and maintaining a benchmark events library for use by the responsible entity in the required
assessment. It is not clear what the events will ultimately be and how the benchmark events library is to be maintained and updated. The SDT should
define and clarify the process for maintaining the benchmark library. GTC also recommends that the PC & TP be involved in the development and/or
approval of the benchmark events.
Likes

0

Dislikes

0

Response
Brittany Millard - Lincoln Electric System - 5
Answer

No

Document Name
Comment
LES supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
Likes

0

Dislikes
Response

0

Katrina Lyons - Georgia System Operations Corporation - 4
Answer

No

Document Name
Comment
GSOC supports Georgia Transmission Corporation's comments:
It is understood the ERO is tasked with developing and maintaining a benchmark events library for use by the responsible entity in the required
assessment. It is not clear what the events will ultimately be and how the benchmark events library is to be maintained and updated.
Likes

0

Dislikes

0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
It is challenging to agree with the proposal due to the vagueness of the requirement. Request an example of the approved benchmark library in order to
assess how requirements R3-R8 will be completed.
Likes

0

Dislikes

0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

No

Document Name
Comment
We support EEI's comments.
Likes

0

Dislikes
Response

0

Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer

No

Document Name
Comment
AECI supports comment provided by Georgia Transmission Corporation
Likes

0

Dislikes

0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

No

Document Name
Comment
Duke Energy does not support suggested R2 language. This requirement requires additional information such as the source of weather data, who will
create cases, how industry input will be incorporated, etc.
Likes

0

Dislikes

0

Response
Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer

No

Document Name
Comment
ISO will need to see the list of Benchmark Events provided by NERC before making a full determination on the R2 Requirement. Initial view is that R2 is appropriate
with the inclusion of responsible entity as this allows flexibility for coordination amongst planning entities.
Likes

0

Dislikes

0

Response
David Jendras Sr - Ameren - Ameren Services - 3

Answer

No

Document Name
Comment
Ameren has concerns about the ERO's Library. What if it is unavailable when we need to perform the study?
Likes

0

Dislikes

0

Response
Colby Galloway - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment
Southern Company has concerns about not being involved in the development of the benchmark events. NERC should set boundaries and guidelines
for the development of extreme weather conditions for analysis, but should not be unilaterally defining the events. It is recommended that “benchmark
event” be defined and the approval process be clarified. The SDT should define and clarify the process for maintaining the benchmark library. In the
spirit of collaboration and mutual interest in benchmark events, it is recommended that entities be involved in the approval of benchmark events. If
NERC is defining benchmark events, then language should also be included to outline how benchmark events are determined and defined, while
allowing for entities to adjust benchmark events for their system, similar to R3.2.
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Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer

No

Document Name
Comment
It is recommended that entities be involved in the development of the benchmark events library. It is not clear how NERC defines and determines the
benchmark events.
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Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

No

Document Name
Comment
Without specifically stating it, the current wording of this requirement puts the responsibility for determining the library of events in the hands of the ERO
and does not explicitly provide the ability for the PC or TP entities to be involved at any point in the development of this library.
If the ERO develops a library of events that are too extreme, this could significantly impact cost of the transmission investment of the PC and TP entities
and ultimately the customers within the PC and TP footprints. If the events are not extreme enough or turn out to be overly severe in one local area or
region and not severe enough in another due to a lack of engagement from regional and local experts, this could also cause distortions in appropriate
planning.
Because the PC and TP entities know their systems (and likely the local climate and weather patterns) better than the ERO, shouldn’t those entities be
at least involved in determining the library of events from which they must select? We suggest that the requirement be reworded to provide the ability
for PCs and TPs to have some control and input for the conditions that are studied for their systems, or even to require the ERO to collaborate with the
PCs and TPs in developing these scenarios, with the ERO having the final decision after considering feedback and comments. There should also be
some guidance provided as to how severe the benchmark cases should be. For example, California’s history of severe weather is very limited and
infrequent due to the tempering effects of the Pacific Ocean, whereas the East coast, Midwest, southwest (and Texas) is more prone to severe swings
in weather and extreme conditions. Some climate change forecasts predict that this situation may change, but which forecast, if any, should be
considered when preparing the benchmark cases should be at least up for discussion.
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Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

No

Document Name
Comment
Although ITC conceptually supports requirement R2, we are withholding formal support until we can see and evaluate some examples of what the ERO
intends to include as benchmark events in the library.

In addition, we support the “responsible entity as identified in requirement R1” language in R2 as it allows flexibility among planning entities to
collectively determine who (e.g., the PC and/or TP) will perform R2.
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Robert Jones - Seattle City Light - 1,3,4,6
Answer

No

Document Name
Comment
Needs more clarity on the definition of the Extreme Temperature Event. It is unclear how the benchmark events will be chosen. There is no guarantee
that there will be an event relevant for every entity. The selection of benchmark events should either be 1) defined as part of the standard and done by
more local entities or 2) allow TPs/PCs to define their own benchmark event if they feel none of the ones offered by the ERO are relevant/appropriate.
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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

No

Document Name
Comment
NIPSCO supports the comments provided by Entergy, ReliabilityFirst, TVA, CHPD, CMS Energy, and MRO.
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Selene Willis - Edison International - Southern California Edison Company - 5
Answer

No

Document Name
Comment
“See comments submitted by the Edison Electric Institute”
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Daniel Gacek - Exelon - 1
Answer

No

Document Name
Comment
Exelon believes it is not appropriate to assign the Electric Reliability Organization (ERO) responsibility that directly impacts the compliance to a standard
requirement. Interested in seeing more detail about how the benchmark library will be managed. There will need to be outlined guidance on where this
data will be stored and who will have access to it. How will the responsible entity work with the Transmission Planner and Planning Coordinator to
determine what goes into these cases and what are the expectations for providing feedback into them? Would it be better for Planning Coordinators to
collaborate to create these instead?
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Amy Wilke - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
ATC generally supports the MRO NSRF comments, and is supplementing them as described below.
More information (and examples) is needed to agree with R2 (including who will develop/ maintain the database and what happens if it is not
maintained, or if data is inaccurate, etc). We appreciate the potential value in having a benchmark event library that acts as a consistent database
where experts have helped to translate the weather data into useable planning information (if done well). There could be considerable work for
responsible entities if the data is not useable or properly maintained, and the responsible entities do not have control over the benchmark event library.
More clarification on criteria and how alternative cases could be submitted for use in the Assessment is needed.
It should be clear that TPL-008 will only be required to use temperature information from the selected benchmark events.
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Kinte Whitehead - Exelon - 3
Answer
Document Name
Comment

No

Exelon believes it is not appropriate to assign the Electric Reliability Organization (ERO) responsibility that directly impacts the compliance to a standard
requirement. Interested in seeing more detail about how the benchmark library will be managed. There will need to be outlined guidance on where this
data will be stored and who will have access to it. How will the responsible entity work with the Transmission Planner and Planning Coordinator to
determine what goes into these cases and what are the expectations for providing feedback into them? Would it be better for Planning Coordinators to
collaborate to create these instead?
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Response
Wayne Guttormson - SaskPower - 1
Answer

No

Document Name
Comment
Support the MRO NSRF and EEI comments.
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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO,WECC, Group Name SPP RTO
Answer

No

Document Name
Comment
SPP has concerns about Requirement R2 as its expectations for the responsible entities to conduct an assessment from a library that does not currently
exist. We understand that EPRI is working with NERC to construct the library to support the requirement’s effort. However, we will find it difficult for the
responsible entities to support this requirement while there is no data to review.
Additionally, we have a concern about the assessment results and how they should align with an area that was closer to the extreme event versus
greater distance from the impacted area.
As we stated before, there is no official library data available for the responsible entities to conduct an assessment as well as compare those results
with other entities to ensure quality results have been produced. Again, it will be difficult for the responsible entities to support this requirement while
there is no data to review and compare results.
SPP recommends that the drafting team coordinate with NERC staff and ensure that the library has been finalized before moving forward with this
requirement. It will be difficult to convince industry to support this effort when there are still too many unresolved issues at this point.
Also, SPP recommends that the drafting team provide more clarity on the expectation of what type of results these assessments are to produce.

Likes

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Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

No

Document Name
Comment
NV Energy believes that it is too vague. NV Energy is concerned that proposed Reliability Standard, TPL-008-1, is being moved forward for industry
approval without any insights into a key element of this Reliability Standard which is the extreme temperature benchmark event library. EEI additionally
does not support making this library a separate document outside of this Reliability Standard. It should be included in the Reliability Standard for
industry review or input. This library should be an attachment within this Reliability Standard and we offer the following proposed changes to
Requirement R2 to address this concern
in boldface below:

R2. Each responsible entity, as identified in Requirement R1, shall select one extreme heat benchmark event and one extreme cold benchmark event,
from the Attachment Xapproved ERO (Extreme Temperature Benchmark Library) for performing the Extreme Temperature Assessment. [Violation
Risk Factor: High] [Time Horizon: Long-term Planning]
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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT is unable to formulate a position on this question without additional information on how the approved benchmark library managed by ERO will
be established and populated, including the underlying criteria, approach, and assumptions. An open and transparent process is crucial, and ERCOT
recommends that Planning Coordinators be allowed to submit extreme heat and cold events based on their historical weather events and statistical
analysis for inclusion in the library.
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Response
Adrian Harris - Adrian Harris On Behalf of: Bobbi Welch, Midcontinent ISO, Inc., 2; - Adrian Harris, Group Name RTO/ISO Council Standard
Review Committee Project 2023-07 TPL-008
Answer

No

Document Name
Comment
As with the Extreme Temperature Assessment definition, the SRC is unable to fully evaluate Requirement R2 without being able to see and evaluate
some example(s) of what the ERO intends to include as benchmark events in the library. Full evaluation of this requirement also requires additional
information on how the approved benchmark library managed by the ERO will be established, populated and maintained over time, including the
underlying criteria, approach and assumptions. An open and transparent process is crucial, and the SRC recommends that Planning Coordinators be
allowed to submit, extreme heat and cold events that are impactful to the reliability of the system based on their historical weather events and statistical
analysis for inclusion in the library.
Additionally, the SRC notes that historical weather events may not fully reflect the potential risks posed by future weather events as the severity,
duration, and complexity of such weather events may increase through time resulting in extreme temperatures, wind lulls and persistent cloud coverage
negatively impacting generation availability and exacerbating electric demands. It is important that the library events, whether synthetic or historical,
present the full time-series of key weather concepts over multiple days to provide entities with sufficient data to build out a full set of system impacts.
Current language does not offer guidance on whether responsible entities should seek to choose more likely or more severe benchmark events from the
approved library in the event these goals conflict. Could lead to under- or overidentification of needs. See for contrast the language around choosing
contingencies: "expected to have more severe System impacts" Will there be an expectation that we justify the events that are chosen?
In addition, the SRC supports the “responsible entity as identified in requirement R1” language in R2 as it allows flexibility among planning entities to
collectively determine who (e.g., the PC and/or TP) will perform R2.
From an improvement perspective, the SRC recommends several edits to the text of R2:
•
•

The word “temperature” be added to benchmark events to align with the Extreme Temperature Assessment definition and to clarify the scope
of the benchmarks being developed.
The word “industry” be added to indicate industry needs to be part of the vetting and approval process to ensure that temperature benchmarks
do not result in infeasible construction requirements.

R2. Each responsible entity, as identified in Requirement R1, shall select one extreme heat temperature benchmark event and one extreme
cold temperature benchmark event, from the industry approved benchmark library maintained by the Electric Reliability Organization (ERO)
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Response
Catrina Martin - Archer Energy Solutions, LLC - 5
Answer
Document Name

No

Comment
Without specifically stating it, the current wording of this requirement puts the responsibility for determining the library of events in the hands of the ERO
and does not explicitly provide the ability for the PC or TP entities to be involved at any point in the development of this library.
If the ERO develops a library of events that are too extreme, this could significantly impact cost of the transmission investment of the PC and TP entities
and ultimately the customers within the PC and TP footprints. If the events are not extreme enough or turn out to be overly severe in one local area or
region and not severe enough in another due to a lack of engagement from regional and local experts, this could also cause distortions in appropriate
planning.
Because the PC and TP entities know their systems (and likely the local climate and weather patterns) better than the ERO, shouldn’t those entities be
at least involved in determining the library of events from which they must select? We suggest that the requirement be reworded to provide the ability
for PCs and TPs to have some control and input for the conditions that are studied for their systems, or even to require the ERO to collaborate with the
PCs and TPs in developing these scenarios, with the ERO having the final decision after considering feedback and comments. There should also be
some guidance provided as to how severe the benchmark cases should be. For example, California’s history of severe weather is very limited and
infrequent due to the tempering effects of the Pacific Ocean, whereas the Midwest (and Texas) is more prone to severe swings in weather and extreme
conditions. Some climate change forecasts predict that this situation may change, but which forecast, if any, should be considered when preparing the
benchmark cases should be at least up for discussion.
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Response
Joseph McClung - JEA - 1
Answer

No

Document Name
Comment
The requirement R2 states “approved benchmark library maintained by the Electric Reliability Organization”, which creates consternation for utilities due
to its ambiguity. Who is approving the benchmark event – the ERO, the Commission, NOAA (or similar agency), Planning Coordinator, Transmission
Planner? The SDT has clearly stated they are not in the position to provide the basis or determine the appropriateness of any specific event. The ERO
may maintain the library, but there needs to be clarity or some kind of vetting process with the participation from the industry on the approval process to
benchmark any extreme heat or cold weather event that gets added to the library of events. Due consideration needs to be given to the geographic
regions and variances in the weather patterns.
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Jessica Cordero - Unisource - Tucson Electric Power Co. - 1 - WECC
Answer
Document Name

Yes

Comment
Events in the ERO library should have industry review and approval prior to inclusion in the ERO library.
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Isidoro Behar - Long Island Power Authority - 1
Answer

Yes

Document Name
Comment
Section 4 (Applicability) should be expanded to indicate and clarify that the ERO is responsible for developing the extreme heat benchmark event(s) and
extreme cold benchmark event(s), and maintaining the benchmark library.
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Michele Tondalo - United Illuminating Co. - 1
Answer

Yes

Document Name
Comment
I agree with this Requirement though I believe that affected Transmission Planners are eager to see what these benchmark events look like; and if the
event data will include all of the necessary information for development of the study cases. Furthermore, will these Benchmark events be inclusive of
the impacts from climate change; particularly on the extreme heat events?
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Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer
Document Name

Yes

Comment
Our SME agrees with this Requirement though he believes that affected Transmission Planners are eager to see what these benchmark events look
like; and if the event data will include all of the necessary information for development of the study cases. Furthermore, will these Benchmark events be
inclusive of the impacts from climate change; particularly on the extreme heat events?
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Richard Vendetti - NextEra Energy - 5
Answer

Yes

Document Name
Comment
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0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
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Response
Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer

Yes

Document Name
Comment
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Kimberly Turco - Constellation - 6
Answer
Document Name
Comment
Constellation has no comments
Kimberly Turco on behalf of Constellation Segments 5 and 6
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Alison MacKellar - Constellation - 5
Answer
Document Name
Comment
Constellation has no comments
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Junji Yamaguchi - Hydro-Quebec (HQ) - 5
Answer
Document Name
Comment
Should there be any requirements for developing and maintaining benchmark libraries (in co-operation with EROs), or if that is mandated through
another means?

“Responsible entity” should be defined in the Applicability section or should replaced with “Each Planning Coordinator, in conjunction with its
Transmission Planner(s)...”Suggest to replace 4.1 to “Responsible Entity” instead of “Functional Entity”.
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer
Document Name
Comment
Should there be any requirements for developing and maintaining benchmark libraries (in co-operation with EROs), or if that is mandated through
another means?

“Responsible entity” should be defined in the Applicability section or should replace with “Each Planning Coordinator, in conjunction with its
Transmission Planner(s)...” Suggest replacing 4.1 to “Responsible Entity” instead of “Functional Entity”.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE noticed Requirement R2 requires the Electric Reliability Organization (ERO) to maintain a benchmark library so each responsible entity can
select one extreme heat benchmark event and one extreme cold benchmark event. Texas RE requests the SDT’s reasoning for choosing the ERO as
the responsible entity to maintain the benchmark library, rather than the RC or PC. Texas RE notes that, as currently drafted, it appears entities could
select any available benchmark case. Is the SDT’s intent that as part of the ERO’s maintenance activities, the ERO select appropriate cold and heat
benchmark cases for responsible entities?

Texas RE notes that there is a significant amount of variation in extreme heat and cold benchmark events depending upon the climatological zone in
which an applicable transmission planning entity is located. As an alternative, the SDT may wish to consider establishing more objective criteria for
responsible entities to select benchmark events based on their particular circumstances. By way of example, benchmark events could be established

based on the 95th percentile maximum or minimum temperature events experienced over a 72-hour period, which has been adopted for transmission
and generation weatherization activities in the ERCOT Interconnection.
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Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments.
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4. Do you agree with the proposed TPL-008-1 Reliability Standard Requirements R3 – R8 (benchmark planning cases and analyses)? If you
do not agree, please provide your recommendation and, if appropriate, technical or procedural justification.
Michael Goggin - Grid Strategies LLC - 5
Answer

No

Document Name
Comment
First, to comply with FERC Order 896, the standard should specify that benchmark events and Extreme Temperature Assessments will account for
concurrent/correlated outages of generators during extreme heat and cold events. In Order 896 paragraph 88, FERC directs “NERC to require under
the new or revised Reliability Standard the study of concurrent/correlated generator and transmission outages due to extreme heat and cold events in
benchmark events,” explaining in paragraph 89 that “it is necessary that responsible entities evaluate the risk of correlated or concurrent outages and
derates of all types of generation resources and transmission facilities as a result of extreme heat and cold events.”
The drafts of TPL-008 and the associated “Consideration of FERC Order 896 Directives” document appear to put the burden on responsible entities and
not NERC for accounting for correlated outages: “This directive is addressed in proposed TPL-008-1 through Requirement R3 Part 3.2. The responsible
entity is obligated to modify the benchmark planning cases to include seasonal and temperature dependent adjustment for Load, generation,
Transmission, and transfers which represent the selected benchmark events.”[1]
Having responsible entities and not NERC conduct this adjustment increases the risk that different regions will use inconsistent methods for doing so,
and at worst responsible entities that want to avoid addressing reliability concerns through a Corrective Action Plan will use unrealistically low
assumptions for the rate of correlated generator outages or other input assumptions like load and transfers. This assumption can have such a large
impact on results it cannot be left to responsible entities, and should be made by NERC. The drafting team’s Technical Rationale used similar logic in
deciding that NERC (the Electric Reliability Organization or ERO) should assemble the benchmark planning cases: “to ensure consistency across
regions, it is necessary for the ERO to have the responsibility for determining the suitability of benchmark events to represent probable future
conditions.”
Given the significant variation in the rates at which different fuel types experience correlated outages,[2] and rapid changes in the generation mix that
may cause the future power system to have greater or lesser exposure to correlated outage risk, it is particularly important for the benchmark events
and Extreme Temperature Assessments to account for the concurrent/correlated outage risk of each fuel type in the future generation mix. In recent
cold snap events, gas generator outages due to equipment failures and fuel supply interruptions have accounted for the majority of outages. NERC
GADS data can be used to assess the rate of correlated outages and derates of generators by fuel type.{C}[3]
Second, the benchmark cases and Extreme Temperature Assessments should account for changes to generation, demand, and transmission resulting
from climate change, electrification of heating, and other factors that are affecting the risk posed by extreme heat and cold. Accounting for how climate
change is increasing the frequency and magnitude of extreme heat and cold events is consistent with FERC’s Order 896 directive in paragraph 40: “We
also direct NERC to ensure the reliability standard contains appropriate mechanisms for ensuring the benchmark event reflects up-to-date
meteorological data. The increasing intensity, frequency, and unpredictability of extreme weather conditions requires that key aspects of the benchmark
events be reviewed, and if necessary, updated periodically to ensure the corresponding benchmark planning cases reflect updated meteorological
data.” Electrification of heating is also increasing the sensitivity of electricity demand to extreme cold conditions, which should be accounted for in the
benchmark cases and Extreme Temperature Assessments.
Third, due to the impact of climate change, electrification, and rapid changes in the generation mix, requirement R8 should require responsible entities
to complete an Extreme Temperature Assessment more frequently than at least once every five calendar years. As noted above, FERC Order 896
specifies that the meteorology underlying benchmark cases should be updated at least every five years, but the generation mix and other grid
conditions can change more rapidly than that. TPL-001 requirement R2 requires Planning Assessments to be conducted annually, and a similar annual
requirement for Extreme Temperature Assessments is appropriate given that extreme heat and cold events are the largest threat to electric reliability.

Finally, the requirement in Section 8.1 under R8 is unclear and may be inadequate. That section states that the Extreme Temperature Assessment shall
include “Assessment of the benchmark planning cases developed under Requirement R4, for one of the years in the Long-Term Transmission Planning
Horizon. The rationale for the year selected for evaluation shall be available as supporting information.” At minimum, that section of R8 should be
modified to provide responsible entities with greater direction on which year or years to assess the planning cases developed under R4. Because
extreme heat and cold risks can evolve over time due to changes in the generation mix, load, and the impact of climate change, R8 should require the
responsible entity to document that the year selected is likely to pose the greatest reliability risk. If it cannot be determined which year is likely to pose
the greatest risk, then the responsible entity should be required to conduct the assessment for all years that may pose the greatest risk. This is
important because of the long and ambiguous timeframe covered by the Long-Term Transmission Planning Horizon, which the NERC Glossary
indicates is the “Transmission planning period that covers years six through ten or beyond when required to accommodate any known longer lead time
projects that may take longer than ten years to complete.” Planning for multiple years is consistent with the requirement in Section 2.1.1. of requirement
R2 for TPL-001, which requires Planning Assessments to examine multiple years by incorporating “System peak Load for either Year One or year two,
and for year five.”[4]

{C}[1]{C} NERC, Consideration of FERC Order 896 Directives (March 2024),
https://www.nerc.com/pa/Stand/Project202307ModtoTPL00151TransSystPlanPerfReqExWe/202307_Consideration%20of%20FERC%20Order%20896%20Directives%20Final_032024.pdf, at 5
{C}[2]{C} See, e.g., FERC and NERC, Winter Storm Elliott Report: Inquiry into Bulk-Power System Operations During December 2022 (October 2023),
https://www.ferc.gov/media/winter-storm-elliott-report-inquiry-bulk-power-system-operations-during-december-2022, at 17; FERC and NERC, The
February 2021 Cold Weather Outages in Texas and the South Central United States (November 2021), https://www.ferc.gov/media/february-2021-coldweather-outages-texas-and-south-central-united-states-ferc-nerc-and, at 16; FERC and NERC, 2019 FERC and NERC Staff Report: The South Central
United States Cold Weather Bulk Electric System Event of January 17, 2018 (July 2019), https://www.ferc.gov/legal/staff-reports/2019/07-18-19-fercnerc-report.pdf; PJM, Analysis of Operational Events and Market Impacts During the January 2014 Cold Weather Events (May 2014),
https://www.pjm.com/~/media/library/reports-notices/weather-related/20140509-analysis-of-operational-events-and-market-impacts-during-the-jan-2014cold-weather-events.ashx.
{C}[3]{C} For example, see the analysis of GADS data provided in S. Murphy et al., Resource adequacy risks to the bulk power system in North America
(February 2018), https://www.sciencedirect.com/science/article/pii/S0306261917318202, with Supplementary Material including outage data available at
https://ars.els-cdn.com/content/image/1-s2.0-S0306261917318202-mmc1.zip
{C}[4]{C} https://www.nerc.com/pa/Stand/Reliability%20Standards/TPL-001-4.pdf
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Response
Catrina Martin - Archer Energy Solutions, LLC - 5
Answer

No

Document Name
Comment
R3 - The responsibility is assigned to “each PC,” but the weather events selected from the ERO library will certainly cross multiple PC footprints in
almost every case. This argues for the development of regional processes and the development of base cases that could be used by multiple PC
entities. Regional planning groups or the regional entities (such as WECC) may be better groups for developing these processes and base cases than
the PC.

o As currently written, R3 does not appear to preclude PCs from working together on this requirement. Does the drafting team envision this as an
acceptable way to meet R3?
o If so, an alternative wording might be: Each Planning Coordinator shall coordinate with other impacted Planning Coordinator(s), Transmission
Planner(s), and other designated study entities to develop and implement joint and/or individual processes for coordinating the development of
benchmark planning cases based on the selected benchmark events as identified in Requirement R2.
R4 - It would be helpful if this requirement (or other NERC guidance for this requirement) would provide additional details on what additional system
models (e.g., steady state and stability) are required and how the required modeling data differs from the current MOD-032 and TPL-001
requirements. There may also be some data requirements for the Extreme Temperature Assessment that are not addressed by the current version of
MOD-032, such as special high/cold temperature Facility Ratings, generation de-rating and dispatch patterns, or climate change forecasts that could
impact the temperature assumptions for load models. Since MOD-032 does not currently address these data requirements, they need to be addressed
in TPL-008 as an appendix, in a Guidelines and Technical Basis section, or in a future modification to MOD-032 itself.
R5 - As with TPL-007 and TPL-001, it appears that the study criteria are set by the “responsible entity” which is negotiated under R1. While the
responsible entity is charged with maintaining system reliability, the criteria will also determine the number of CAPs and amount of transmission
investment that are required to meet TPL-008. TPL-001-5.1 is already triggering the need for additional transmission investment over the coming years,
so TO/GO entities that will actually pay for the upgrades will be further taxed by TPL-008. The implementation plan needs to be long enough so that the
investments for TPL-008 do not coincide closely with the TPL-001-5.1 implementation period.
R5 – This requirement states that the responsible entity “shall have criteria” while R6 states that the responsible entity “shall define and document
criteria?” The wording in R6 appears to be better, since both sets of criteria should be “defined and documented” in each Extreme Temperature
Assessment report. It is suggested that the wording from R6 be used for R5.
R6 - Instability criteria are generally not “adjustable” limits. That is, the system is either unstable or it is not. If the events in the ERO library are too
severe and lead to a significant increase in the events that trigger instability, these could be expensive problems to fix. See comments for R2.
R7 - It would be helpful to see this requirement address the differences between the set of contingencies for TPL-001 rather than an absolute set - this
provides more value for all entities rather than showing a largely duplicative full set of outages.
R7 - P5 events are already very unlikely since they require a fault event plus an equipment failure, which is essentially a multiple outage on par with the
likelihood of a P6 event (which is excluded from this standard). The Extreme Temperature event benchmark cases are very unlikely extreme events to
begin with (and an extreme sensitivity to the TPL-001 studies), which further reduces the likelihood of having a P5 event during an Extreme
Temperature event. In addition, the severity of significant P5 events strongly suggests upgrades will already be identified by the annual Assessment
required by TPL-001.
o Given the amount of work already added by this standard, the low likelihood of the P5 events on par with other excluded events from TPL-001 (such
as P6), and the strong likelihood that impacts from these events are already adequately captured by the TPL-001 Assessment studies, we strongly
recommend removing P5 events from Table 1 of TPL-008.

R8 - While it is a helpful limitation to only require one assessment year from the Long-Term Planning Horizon, this may not be practicable for the
development of CAPs that involve capital investment as these projects require multiple years to permit and construct. The CAPs that involve capital
investment will need to be reviewed and refined as the potential violations move into the Near-Term Planning Horizon and prior to the operating
horizon. TPL-001 studies will not include the conditions and criteria required to address these studies, so separate Extreme Temperature event
benchmark cases will need to be developed for the Near-Term Transmission Planning Horizon to address these cases.

R8 - Especially for the very first Extreme Temperature Assessment, it is possible that a large number of CAPs may be identified for criteria violations
that already exist in the Near-Term Planning Horizon. This will create a backlog of projects which will need to be started immediately to meet the
implementation plan period. These projects will be on top of the P5 projects that are already backlogged for implementation of TPL-001-5.1.

o It is recommended that the implementation plan allow a ten-year period for implementation of CAPs that require capital investment to construct new
facilities. This would also match up well with performing these studies for the Long-Term Transmission Planning Horizon since the studied case could
be a ten year case.

R8.2 - Sensitivity to generation, load and transfers are already studied as part of TPL-001-5.1. The sensitivity additional studies proposed for R8.2 are
unlikely to yield any new information and will be duplicative work for Transmission Planners. The Extreme Temperature Assessment is already a very
extreme sensitivity study itself that should already capture modified load, generation, transmission, and transfers befitting this analysis per R3, so it is
not needed nor appropriate to study sensitivities for sensitivity cases.
R8.2 should be removed entirely to reduce unnecessary workload which will provide information that is duplicative and provide no additional value since
the studies under this standard are already in effect sensitivities in comparison to the Assessment studies under TPL-001.
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Adrian Harris - Adrian Harris On Behalf of: Bobbi Welch, Midcontinent ISO, Inc., 2; - Adrian Harris, Group Name RTO/ISO Council Standard
Review Committee Project 2023-07 TPL-008
Answer

No

Document Name
Comment
The SRC requests the SDT address the following in requirements R3-R8:
R3: The SRC requests the SDT clarify obligations when coordinating with neighboring PCs to perform an Extreme Temperature Assessment. If a PC
performs a planning area study for a “selected benchmark event” that only includes a portion of the PC’s footprint (Part 3.1), the SDT should confirm
that the PC and its associated Transmission Planners have satisfied the obligation under R2 for completing an Extreme Temperature Assessment for
either “one extreme heat benchmark event or one extreme cold benchmark event” for that five-calendar year period (R8).
Does R3.2 imply that inter-Area transfers should be different that those coordinated through the ERAG MMWG process which considers “all
transactions that have confirmed annual firm transmission service along the entire path from source to sink and have a firm energy contract for the
resource”? While operationally during extreme heatwaves and cold snaps each Area should plan their system so as to not rely on neighbors beyond
what is contractually obligated and coordained through the ERAG MMWG process.
In addition, the SRC requests the SDT clarify the “process for coordinating the development of benchmark planning cases among impacted Planning
Coordinator(s),” and specifically:
•
•

How far must an entity go, i.e. are Tier 1 neighbors sufficient or must an entity go further?
Can coordinating on the model build for a given event satisfy this requirement?

Similarly, Requirement R3 should also be revised to clarify how conflicts will be resolved if different Planning Coordinators within the same
Interconnection have incompatible processes for selecting benchmark events, defining the planning study boundary area, and coordinating with other
impacted entities. This clarification should address scenarios in which three or more impacted, geographically contiguous Planning Coordinators within

the same Interconnection all select different, incompatible benchmark events (as allowed by Requirement R1) to study. The SRC requests that this
clarification address the following topics, along with any other topics that may need to be addressed:
•
•

Does the standard require all PCs to support all alternate PC studies including data exchange for the various temperature dependent
information as well as the study schedule?
What happens if an entity is unwilling to cooperate?

Finally, to maintain consistency with existing practice under TPL-001-5.1 and avoid introducing unnecessary complexity to the TPL-008 coordination
process, Requirement R3 should be revised to indicate that Planning Coordinators and Transmission Planners are not required to coordinate with
entities in different Interconnections. TPL-001-5.1 Requirement R8 requires Planning Coordinators to distribute Planning Assessment results to adjacent
Planning Coordinators. However, Revising Requirement R3 in TPL-008 to indicate that coordination with entities in other Interconnections is not
required would help optimize the overall efficiency and effectiveness of TPL-008.
R4.The SRC supports the use of MOD-032 to obtain the necessary data and asks the SDT to consider whether MOD-032 needs to be modified to
acquire information unique to TPL-008. The SRC is concerned that MOD-032 does not currently include requirements addressing the necessary
temperature-dependent information for load, generation, transmission, and transfers. If this is not specifically addressed in MOD-032 it will be very
difficult to require the provision of this information.
R5.The SRC has concerns with R5 as it may be duplicative of work that is already occurring under TPL-001-5.1. Specifically, it is unclear how the
criteria for “steady state voltage limits and post-Contingency voltage deviations” under TPL-008, R5 differs from what entities have defined under TPL001-5.1, and consequently, it is unclear why Requirement R5 is needed. The SRC requests that the drafting team provide an explanation of the
need for R5.
R6.The SRC has concerns with R6 as R6 may duplicate work that is already occurring under TPL-001-5.1, PRC-006, and other Reliability Standards.
Therefore, the SRC asks the SDT to describe the need drivers for R6 by identifying where extreme temperature events have resulted in system
instability, uncontrolled separation, or Cascading.
R6. Does “instability” need to be further defined under this standard? R6 already qualifies instability as the prior IROL definition: “identify System
instability for conditions such as Cascading, voltage instability, or uncontrolled islanding.”
The SRC recommends leaving this flexible as many entities have already defined this for their footprint in accordance with FAC-014.
R7. To clarify that the Extreme Temperature Assessment is limited to the planning study area boundary defined in Part 3.1, the SRC requests the SDT
modify requirement R7 as follows:
R7. Each responsible entity, as identified in Requirement R1, shall identify Contingencies used in performing the Extreme Temperature Assessment for
each of the event categories in Table 1 that are expected to produce more severe System impacts within the planning study area boundary defined in
Part 3.1. The rationale for those Contingencies selected for evaluation shall be available as supporting information.
R8. The SRC recommends that Requirement R8 be revised to clarify whether the case used needs to be a Long-Term case at the time the study is
completed or it just when the case building is completed, as two to three years typically elapse between the completion of the case build and the
completion of the studies that use the case
The technical rationale for R8 quotes the FERC order that sensitivity cases, “should consider including conditions that vary with temperature such as
load, generation, and system transfers.” If the temperature is changed, does that imply that a different storm is selected from R2 which would then also
change the study boundary conditions? Also this would increase the complexity of the temperature dependence of generation and transmission
resources.
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Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

No

Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments.
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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
Requirement R3: To maintain consistency with existing practice under TPL-001-5.1 and avoid introducing unnecessary complexity to the TPL-008
coordination process, Requirement R3 should be revised to indicate that Planning Coordinators and Transmission Planners are not required to
coordinate with entities in different Interconnections. TPL-001-5.1 Requirement R8 requires Planning Coordinators to distribute Planning Assessment
results to adjacent Planning Coordinators. However, ERCOT and its neighboring Planning Coordinators in the Eastern and Western Interconnections
have not historically construed Requirement R8 to require distribution of Planning Assessment results between them. Requiring such communication
would be unnecessary because Interconnections connect to each other only through direct current (DC) ties, and DC ties cannot be used to solve
planning criteria violations on an alternating current (AC) system because the operation of DC ties is solely determined by manual actions requiring
approval by multiple entities. Because the various Interconnections are not synchronized with each other, the only purpose that could be served by
requiring Planning Coordinators in different Interconnections to coordinate extreme weather planning would be to address a forecasted generation
insufficiency in one Interconnection. However, as the Technical Rationale notes, resource adequacy issues are beyond the scope of this proceeding
under Order No. 896. Revising Requirement R3 in TPL-008 to indicate that coordination with entities in other Interconnections is not required would
help optimize the overall efficiency and effectiveness of TPL-008.

Requirement R3 should also be revised to clarify how conflicts will be resolved if different Planning Coordinators within the same Interconnection have
incompatible processes for selecting benchmark events, defining the planning study boundary area, and coordinating with other impacted entities. This
clarification should address scenarios in which three or more impacted, geographically contiguous Planning Coordinators within the same
Interconnection all select different, incompatible benchmark events (as allowed by Requirement R1) to study.

Requirement R8: ERCOT recommends that Requirement R8 be revised to clarify whether the case used needs to be a Long-Term case at the time the
study is completed or just when the case building is completed, as two to three years typically elapse between the completion of the case build and the
completion of the studies that use the case.
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Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

No

Document Name
Comment
EEI does not agree with the language contained in requirements R3, R4, R7, and R8 for the reasons expressed below. (See the proposed changes in
boldface to Requirement R3 below)

Proposed changes to Requirement R3:
{C}1. {C}EEI suggests it would be clearer to replace “impacted” with adjoining or neighboring Planning Coordinators since they would be the only
impacted PCs.
{C}2.

{C}EEI also suggests some changes to the subparts of Requirement R3 to better clarify the required tasks under the PC process.

R3. Each Planning Coordinator shall develop and implement a process for coordinating the development of benchmark planning cases among
adjoining Planning Coordinator(s), Transmission Planner(s), and other designated study entities under their purviewbased on the selected to
ensure benchmark events as identified in Requirement R2 are coordinated. This process shall include: [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
{C}3.1. Define theReview of the planning study area boundary boundaries under each Transmission Planner, based to ensure study
completeness.
{C}3.2. Verification that Modify the benchmark planning cases to include seasonal and temperature dependent adjustment for Load, generation,
Transmission, and transfers which represents the selected benchmark events.

Proposed revisions to Requirement R4
EEI suggests the subparts of Requirement R8 are better placed under Requirement R4 with the edits suggested below:
R4. Each responsible entity, as identified in Requirement R1, shall develop and maintain System models within its planning area for performing the
Extreme Temperature Assessment. The System models shall use data consistent with that provided in accordance with the MOD-032 standard,
supplemented by other sources as needed, and shall represent projected System conditions based on the selected benchmark events as
identified in Requirement R2. System models shall be developed for the following conditions: [Violation Risk Factor: High] [Time Horizon: Longterm Planning]

4.1 System conditions based on each benchmark event selected in Requirement R2 for one of the years in the Long-Term Transmission
Planning Horizon.

4.2 For each of the models developed for Requirement R4 Part 4.1, a sensitivity model shall be developed to demonstrate the impact of
changes to the basic assumptions used in the model. To accomplish this, the sensitivity model shall include, at a minimum, changes to one
of the following conditions:

{C}·

Generation,

{C}·

Real and reactive forecasted Load, or

{C}·

Transfers.

Proposed change to Requirement R7:
EEI disagrees with including a requirement to have a documented rationale for the Contingencies selected because it represents an unnecessary
administrative burden.

R7. Each responsible entity, as identified in Requirement R1, shall identify the Contingencies used in performing the Extreme Temperature
Assessment for each of the event categories in Table 1 that are expected to produce more severe System impacts within its planning area. The
rationale for those Contingencies selected for evaluation shall be available as supporting information. [Violation Risk Factor: High] [Time
Horizon: Long-term Planning]

Proposed changes to Requirement R8
EEI suggests that subparts 8.1 and 8.2 should be placed under Requirement R4. In addition to this change the last sentence in R8 referencing those
subparts should be removed. See EEI comments to Requirement R4 below.

R8 Each responsible entity, as identified in Requirement R1, shall complete an Extreme Temperature Assessment of the Long-Term Transmission
Planning Horizon at least once every five calendar years, using the benchmark planning cases and the System models identified in Requirement R3
and R4, and the Contingencies identified in Requirement R7 for each of the event categories in Table 1, and document assumptions and results of the
steady state and stability analyses. The Extreme Temperature Assessment shall include the following. [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO,WECC, Group Name SPP RTO
Answer
Document Name
Comment

No

SPP raises concerns regarding the coordination among all entities impacted by Requirement R3. We understand that this coordination extends to all
Planning Coordinators, including those outside the event area, potentially leading to unnecessary administrative burdens.
Additionally, there's apprehension about planning models not adequately reflecting real-time operational needs. It's challenging to envision a process
ensuring proper alignment between planning and operational models, especially given unresolved issues like data collection discrepancies between
different models.
Regarding Requirement R4 and the use of the MOD-032 Standard for data collection, SPP questions its suitability for assessing Inverter-Based,
Distributed Energy, and Energy Storage Resources, given unresolved project directives.
Concerning Requirement R7, ambiguity exists regarding whether specific studies or all studies implied by Table 1 are required. SPP suggests the
drafting team clarify expectations and align efforts with Project 2022-02 regarding MOD-032.
Lastly, SPP seeks clarification on the purpose of sensitivity analyses in sub-part 8.2 and its association with MOD-032 data collection. They recommend
clarity on the necessity of sensitivity analyses and its relation to data collection from the MOD-032 model build.
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Wayne Guttormson - SaskPower - 1
Answer

No

Document Name
Comment
Support the MRO NSRF and EEI comments.
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Kinte Whitehead - Exelon - 3
Answer

No

Document Name
Comment
R3 - Would like more information about how the boundary is determined/defined. Perhaps specify factors in more detail that would need to be
considered when building base case (N-0).

R4- It is not clear how the ratings set will be identified. Additionally, there is language that states, “develop and maintain System models within its
planning area for performing the Extreme Temperature Assessment.” While the assessment is performed at least once every five years, is there an
expectation that these models are built and maintained more frequently? These models could be ad-hoc, which would not be maintained.
Additional suggestion: Add two terms to the NERC Glossary defining System Models and Planning Cases.
R7 – Need clarification on what projects to include in model year selected.
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer

No

Document Name
Comment
Regarding R3 and R4—it is not clear what the difference is between “planning cases” (R3) and “system models” (R4). These are not defined in the
NERC glossary, and their use here should be clarified.

Regarding R5, FAC-014-3 R6 requires Planning Coordinators and Transmission Planners to use facility ratings, voltage and stability limits that are
equal or more limiting than its respective Reliability Coordinators. Presumably this is intended to give PCs/TPs more leeway in criteria for extreme
events, but unless some exception is made for FAC-014-3 R6, there may be no further room possible (particularly if the ordinary planning limits are
equal to the operational limits, which is probably typical).

R7 should clearly indicate which contingency categories are required.

R4, R5, R6, R7 and R8: “Responsible entity” should be defined in the Applicability section or should replace with “Each Planning Coordinator, in
conjunction with its Transmission Planner(s)...”). Suggest replacing 4.1 to “Responsible Entity” instead of “Functional Entity”.

R6: “….to identify instability, uncontrolled separation, or Cascading” of what? The System? Outages? If that is the case, suggest specifying “to identify
instability, uncontrolled separation, or Cascading of the System” or “to identify instability, uncontrolled separation, or Cascading outages”.
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Amy Wilke - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
ATC generally supports the MRO NSRF comments, and is supplementing them as described below.
R4: During the 4/12/24 workshop, SDT mentioned that one purpose of including R4 and the reference to MOD-032 is to allow the collection of
generation and transmission data related to the extreme heat and cold benchmark events. How will MOD-032 allow for the collection of additional
information related to the extreme heat and cold events? We recognize that MOD-032-1 Attachment 1 includes a provision for “other information
requested by the PC or TP necessary for modeling purposes” but believe that this has not been successful/ adequate in the past and may not be
appropriate in TPL-008. Given this, would updates or modifications be needed to MOD-032 or related documents to get extreme weather load
data? Does the extreme temperature data collection need to involve changes to MOD-031 for extreme weather load forecast data?
R4: Besides establishing the ability for responsible entities to collect data related to extreme heat/ cold, how is R4 different from R3? If a reference to
MOD-032 will not adequately allow for the collection of extreme temperature data, then R4 should a) be updated with an existing method for data
collection, b) the team may need to propose additional changes to exiting processes, or c) remove R4.
R5: Why does R5 only reference voltage and not thermal constraints? If the Extreme Weather Assessment voltage criteria could be different than
regular criteria, then could thermal criteria be different as well?
R6: Is the identification of “instability, uncontrolled separation, or Cascading” expected to be different for the Extreme Temperature Assessment? And
not the same as IROL?
R5, R6, R7: Because there are no longer Planning Horizon SOLs with the new FAC-014-3 and the PC and TP need to follow the RC SOL Methodology,
R5, R6, and R7 should not contradict that.
R8: Should R8 refer to “modified benchmark planning cases” per R3.2?
R8.2: It is not clear how many sensitivities may be needed (believe only one for heat and cold each). We do not want this analysis to become onerous.
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Daniel Gacek - Exelon - 1
Answer

No

Document Name
Comment
R3 - Would like more information about how the boundary is determined/defined. Perhaps specify factors in more detail that would need to be
considered when building base case (N-0).

R4- It is not clear how the ratings set will be identified. Additionally, there is language that states, “develop and maintain System models within its
planning area for performing the Extreme Temperature Assessment.” While the assessment is performed at least once every five years, is there an
expectation that these models are built and maintained more frequently? These models could be ad-hoc, which would not be maintained.
Additional suggestion: Add two terms to the NERC Glossary defining System Models and Planning Cases.
R7 – Need clarification on what projects to include in model year selected.
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Selene Willis - Edison International - Southern California Edison Company - 5
Answer

No

Document Name
Comment
“See comments submitted by the Edison Electric Institute”
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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

No

Document Name
Comment
NIPSCO supports the comments provided by Entergy, ReliabilityFirst, AEP, BPA, WPP, and CMS Energy.
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Robert Jones - Seattle City Light - 1,3,4,6
Answer
Document Name

No

Comment
R3: Need more clarification on the requirements of the process among impacted utilities (who is impacted? And why?). The benchmark base cases may
not be covered by R3 depending on how utilities may define their process or methodology. The boundary or the area may not match the benchmark
event. Will PCs/TPs have to participate in development of multiple benchmark cases from various adjacent/impacted utilities? What requirements exist
to enforce TPs participating in case building for a benchmark case they have not selected? Or will there only be one benchmark event per area (in
which case why is each separate PC defining their own coordination process).
R4: No comments.
R5: Wouldn’t this overlap with TPL-001? Are they expected to be different criteria?
R6: Same comment as R5. This appears to overlap TPL-001… is there any reason the criteria/methodology would be different than for TPL001? Need more guidance. A benchmark event may not fall under entity’s (utilities) criteria or methodology depending on interpretation and definition of
Extreme Temperature by each entity. Need more regional guidance.
R7: The table should be reformatted. It appears to be two tables in one.
R8: The language in this requirement is very vague. Does this apply to steady state or transient stability? According to Table 1 contingency definitions
seem to include all. What about existing generation outages? Do we run P3 and P6 contingencies on top of the existing outages?

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Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

No

Document Name
Comment
ITC requests clarification on the following:

R3. Please clarify the drafting team’s intent for the coordinate with others. Is this just the adjacent PCs. Additionally, for events that only cover a
limited portion of the PCs footprint, is the intent that they would need to complete a second set of hot and cold events for the remaining portion of their
footprint?

R4. Does the drafting team feel it would be necessary to add any additional data to the table in MOD-032 to complete this work?

R5 and R6. If a TP or PC believes that the work performed for a different standard will cover work required under TPL-008, can a provision for this be
added to the standard?

R7 and R8. No comment.
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Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

No

Document Name
Comment
R3 - The responsibility is assigned to “each PC,” but the weather events selected from the ERO library will certainly cross multiple PC footprints in
almost every case. This argues for the development of regional processes and the development of base cases that could be used by multiple PC
entities.
As currently written, R3 does not appear to preclude PCs from working together on this requirement. Does the drafting team envision this as an
acceptable way to meet R3?
If so, an alternative wording might be: Each Planning Coordinator shall coordinate with other impacted Planning Coordinator(s), Transmission
Planner(s), and other designated study entities to develop and implement joint and/or individual processes for coordinating the development of
benchmark planning cases based on the selected benchmark events as identified in Requirement R2.

R4 - It would be helpful if this requirement (or other NERC guidance for this requirement) would provide additional details on what additional system
models (e.g., steady state and stability) are required and how the required modeling data differs from the current MOD-032 and TPL-001
requirements. There may also be some data requirements for the Extreme Temperature Assessment that are not addressed by the current version of
MOD-032, such as special high/cold temperature Facility Ratings, generation de-rating and dispatch patterns, or climate change forecasts that could
impact the temperature assumptions for load models. Since MOD-032 does not currently address these data requirements, they need to be addressed
in TPL-008 as an appendix, in a Guidelines and Technical Basis section, or in a future modification to MOD-032 itself.
R5 – This requirement states that the responsible entity “shall have criteria” while R6 states that the responsible entity “shall define and document
criteria?” The wording in R6 appears to be better, since both sets of criteria should be “defined and documented” in each Extreme Temperature
Assessment report. It is suggested that the wording from R6 be used for R5.
R6 - Instability criteria are generally not “adjustable” limits. That is, the system is either unstable or it is not. If the events in the ERO library are too
severe and lead to a significant increase in the events that trigger instability, these could require extensive CAPs. See comments for R2.
R7 - It would be helpful to see this requirement address the differences between the set of contingencies for TPL-001 rather than an absolute set - this
provides more value for all entities rather than showing a largely duplicative full set of outages.

R7 - P5 events are already very unlikely since they require a fault event plus an equipment failure, which is essentially a multiple outage on par with the
likelihood of a P6 event (which is already excluded from this standard). Furthermore, the severity of significant P5 events strongly suggests upgrades
will already be identified by the annual Assessment required by TPL-001. Provided the strong likelihood that impacts from these events are already
adequately captured by the TPL-001 Assessment studies, we strongly recommend removing P5 events from Table 1 of TPL-008.
R8 – In order to avoid backlog of projects which will need to be started immediately to meet the implementation plan period, it is recommended that the
implementation plan allow a ten-year period for implementation of CAPs that require capital investment to construct new facilities. This would also
match up well with performing these studies for the Long-Term Transmission Planning Horizon.
R8.2 - The Extreme Temperature Assessment is already a very extreme sensitivity study itself that should already capture modified load, generation,
transmission, and transfers befitting this analysis per R3, so it is not needed nor appropriate to study sensitivities for sensitivity cases. As a result, we
strongly recommend R8.2 to be removed. Instead, PG&E recommends requiring in the benchmark cases that load, generation, system configurations,
facility ratings, etc. should match the assumptions for extreme weather conditions.

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Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer

No

Document Name
Comment
SDT should consider combining R3 and R4.
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Colby Galloway - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment
Southern Company recommends that the standard drafting team clarify R3.1 and the broader process for R3. As written, an unintended consequence
will likely be an extreme amount of workload for the Planning Coordinator(s) to develop cases. The requirement of impacted Planning Coordinator(s) to
provide support in a timely manner should also be defined.

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David Jendras Sr - Ameren - Ameren Services - 3
Answer

No

Document Name
Comment
R3.1: Ameren suggests making a definition of wide area because it is currently unclear.
R3.2: The requirement includes "Transmission", do Transmission line ratings need to be modified to reflect the extreme temperature assessment?
R4: Currently, MOD-032 does not specifically require extreme temperature data for load and generation. Does MOD-032 need to be updated to
consider the extreme temperature data requirement as part of this standard?
R5: Is the expectation of the standard drafting team to have two different acceptable voltage limits for TPL-001-5 and TPL-008, or is it up to the
Responsible Entity to determine if they can both align?
R7: In Table 1, the criteria are not clear as to whether the steady state performance criteria apply to all of the BES or just BES elements 200kv and
above.
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Junji Yamaguchi - Hydro-Quebec (HQ) - 5
Answer

No

Document Name
Comment
Regarding R3 and R4—it is not clear what the difference is between “planning cases” (R3) and “system models” (R4). These are not defined in the
NERC glossary, and their use here should be clarified.

Regarding R5, FAC-014-3 R6 requires Planning Coordinators and Transmission Planners to use facility ratings, voltage and stability limits that are
equal or more limiting than its respective Reliability Coordinators. Presumably this is intended to give PCs/TPs more leeway in criteria for extreme
events, but unless some exception is made for FAC-014-3 R6, there may be no further room possible (particularly if the ordinary planning limits are
equal to the operational limits, which is probably typical).

R7 should clearly indicate which contingency categories are required.

R4, R5, R6, R7 and R8: “Responsible entity” should be defined in the Applicability section or should replaced with “Each Planning Coordinator, in
conjunction with its Transmission Planner(s)...” ). Suggest to replace 4.1 to “Responsible Entity” instead of “Functional Entity”.

R6: please complete the phrase“….to identify instability, uncontrolled separation, or Cascading”. For example, are we identifying instability, uncontrolled
separation, or Cascading of the System? The Interconnection? If that is the case, we suggest to specify “to identify instability, uncontrolled separation,
or Cascading of the System” or “to identify instability, uncontrolled separation, or Cascading Interconnection”.
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Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer

No

Document Name
Comment
For R3: Coordination between RCs needs to be clarified. If each RC were to choose a different Benchmark Event to study, does each neighboring RC need to provide
data to others? What If two or more PCs choose different benchmark events to study. Will this create an additional work load for those neighboring entities?
For R3.1. This calls for a defined “planning study area”. Is this meant to be different than a PC’s “Planning Area”. Clarification is needed to show that the planning
study area remains within the PC’s planning area, so that for example a Benchmark Event affecting Ohio does not need to be studied by New England.
R4: Should be changed so that the System Model only needs to be updated for the year in which studies will be performed versus annual model updates as required
by MOD-032.
R5: Is this duplicative to TPL-001? Could this create a Double Jeopardy situation where two requirements would be violated for a single issue?
R6: Is this duplicative to TPL-001 or other standards (PRC?)? Will this create a Double Jeopardy situation where two requirements would be violated for a single
issue?
R7: Suggest changing “Planning area” to “Planning Study Area”. Same reasoning as R3.1 comment above.
R8: No Additional Comments
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Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF

Answer

No

Document Name
Comment
R3.2 includes “Transmission” which is omitted from the Rationale Document (R3) – please define intent of using Transmission in R3.2. Additionally, R3
uses the phrase “and other designated study entities” – please define who the other entities are and why they are needed relative to this standard.
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Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer

No

Document Name
Comment
AECI supports comment provided by Georgia Transmission Corporation
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0

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Mike Magruder - Avista - Avista Corporation - 1
Answer

No

Document Name
Comment
We support EEI's comments.
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Katrina Lyons - Georgia System Operations Corporation - 4
Answer
Document Name

No

Comment
GSOC supports Georgia Transmission Corporation's comments:
R3:

•
•

Replace “Each Planning Coordinator shall” with “Each responsible entity, as identified in Requirement R1, shall”. This may require supplemental
wording edits in the requirement.
The inclusion of “other designated study entities” is not clear.
The SDT should consider combining this requirement with R4.

•

The SDT should consider combining this requirement with R3.

•

The SDT should consider utilizing the recently adopted NERC Glossary term, System Voltage Limits, in this requirement. “…shall have a
criteria for acceptable System Voltage Limits for performing the Extreme Temperature Assessment…”
Since this requirement appears to refer to steady-state voltage, the post contingency voltage deviation portion of the existing requirement
should be removed. The resultant steady-state voltage level being outside of acceptable high and low limits is the point of concern. For
example, if a low voltage criterion is 0.92 p.u., then voltages below this limit would violate this particular criteria regardless of whether the
beginning voltage was 0.95 p.u., 0.98 p.u., or any other voltage level.

•

R4:

R5:

•

R6:
•
•

The following bullet contains a wording addition to clarify the applicability of this requirement to System-wide impacts. This is also consistent
with wording in other Reliability Standards when referencing these types of impacts.
“Each responsible entity, as identified in Requirement R1, shall define and document the criteria or methodology used in the Extreme
Temperature Assessment analysis to identify instability, uncontrolled separation, or Cascading of the Bulk Electric System.”

R7 & R8:
•
•

•

It does not appear likely that P0 events would be “expected to produce more severe System impacts”. Therefore, those events would likely not
be part of a benchmark assessment as R7 & R8 are currently written. This is true to a lesser extent to P1 events. Additional clarity to this
requirement is needed to determine when and if P0 and P1 events are required.
The standard does not clearly and specifically state whether steady-state and/or stability analysis is to be performed for the identified events as
TPL-001 does for instance. The SDT should consider modifying R7 to allow the responsible entity to develop a methodology or rationale in the
performance of a benchmark event to appropriately assess it for that entity’s planning area, otherwise, additional clarity in the analysis
expectations is needed. Different weather events would require a different consideration of applicable contingencies and analysis approaches.
Some of the lack of clarity may be related to the lack of clarity around the composition of the benchmark events to be determined. If these
benchmark events are limited to temperature profiles versus temperature profiles and potential resultant generation unavailability (for example),
the responsible entity’s analysis approach will potentially vary.

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Response
Brittany Millard - Lincoln Electric System - 5
Answer

No

Document Name
Comment
LES supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
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Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
R3:

•
•

Replace “Each Planning Coordinator shall” with “Each responsible entity, as identified in Requirement R1, shall”. This may require supplemental
wording edits in the requirement.
The inclusion of “other designated study entities” is not clear.
The SDT should consider combining this requirement with R4.

•

The SDT should consider combining this requirement with R3.

•

The SDT should consider utilizing the recently adopted NERC Glossary term, System Voltage Limits, in this requirement. “…shall have a
criteria for acceptable System Voltage Limits for performing the Extreme Temperature Assessment…”
{Since this requirement appears to refer to steady-state voltage, the post contingency voltage deviation portion of the existing requirement
should be removed. The resultant steady-state voltage level being outside of acceptable high and low limits is the point of concern. For
example, if a low voltage criterion is 0.92 p.u., then voltages below this limit would violate this particular criteria regardless of whether the
beginning voltage was 0.95 p.u., 0.98 p.u., or any other voltage level.

•

R4:

R5:

•

R6:
•
•

The following bullet contains a wording addition to clarify the applicability of this requirement to System-wide impacts. This is also consistent
with wording in other Reliability Standards when referencing these types of impacts.
“Each responsible entity, as identified in Requirement R1, shall define and document the criteria or methodology used in the Extreme
Temperature Assessment analysis to identify instability, uncontrolled separation, or Cascading of the Bulk Electric System.”

R7 & R8:
•

It does not appear likely that P0 events would be “expected to produce more severe System impacts”. Therefore, those events would likely not
be part of a benchmark assessment as R7 & R8 are currently written. This is true to a lesser extent to P1 events. Additional clarity to this
requirement is needed to determine when and if P0 and P1 events are required.

•

•

The standard does not clearly and specifically state whether steady-state and/or stability analysis is to be performed for the identified events as
TPL-001 does for instance. The SDT should consider modifying R7 to allow the responsible entity to develop a methodology or rationale in the
performance of a benchmark event to appropriately assess it for that entity’s planning area, otherwise, additional clarity in the analysis
expectations is needed. Different weather events would require a different consideration of applicable contingencies and analysis approaches.
Some of the lack of clarity may be related to the lack of clarity around the composition of the benchmark events to be determined. If these
benchmark events are limited to temperature profiles versus temperature profiles and potential resultant generation unavailability (for example),
the responsible entity’s analysis approach will potentially vary.

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Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

No

Document Name
Comment
For R3, AZPS suggests it would be clearer to replace “impacted” with adjoining or neighboring Planning Coordinators since they would be the only
impacted PCs.
For R4, AZPS is in agreement with developing system models as described, however, AZPS does not agree that it is necessary to maintain or update
the model between studies. AZPS suggests the words “and maintain” be struck.
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Glen Farmer - Avista - Avista Corporation - 5
Answer

No

Document Name
Comment
EEI does not agree with the language contained in requirements R3, R4, R7, and R8 for the reasons expressed below. (See the proposed changes in
boldface to Requirement R3 below)

Proposed changes to Requirement R3:
1. EEI suggests it would be clearer to replace “impacted” with adjoining or neighboring Planning Coordinators since they would be the only impacted
PCs.

2. EEI also suggests some changes to the subparts of Requirement R3 to better clarify the required tasks under the PC process.
R3. Each Planning Coordinator shall develop and implement a process for coordinating the development of benchmark planning cases among adjoining
Planning Coordinator(s), Transmission Planner(s), and other designated study entities under their purview to ensure benchmark events as identified in
Requirement R2 are coordinated. This process shall include: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
3.1. Review of the planning study area boundaries under each Transmission Planner, to ensure study completeness.
3.2. Verification that the benchmark planning cases include seasonal and temperature dependent adjustment for Load, generation, Transmission, and
transfers which represents the selected benchmark events.

Proposed revisions to Requirement R4
EEI suggests the subparts of Requirement R8 are better placed under Requirement R4 with the edits suggested below:
R4. Each responsible entity, as identified in Requirement R1, shall develop and maintain System models within its planning area for performing the
Extreme Temperature Assessment. The System models shall use data consistent with that provided in accordance with the MOD-032 standard,
supplemented by other sources as needed. System models shall be developed for the following conditions: [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]

4.1 System conditions based on each benchmark event selected in Requirement R2 for one of the years in the Long-Term Transmission Planning
Horizon.
4.2 For each of the models developed for Requirement R4 Part 4.1, a sensitivity analysis shall be performed to demonstrate the impact of changes to
the basic assumptions used in the model. To accomplish this, the sensitivity analysis shall include, at a minimum, changes to one of the following
conditions:

• Generation,
• Real and reactive forecasted Load, or
• Transfers.

Proposed change to Requirement R7:
EEI disagrees with including a requirement to have a documented rationale for the Contingencies selected because it represents an unnecessary
administrative burden.

R7. Each responsible entity, as identified in Requirement R1, shall identify the Contingencies used in performing the Extreme Temperature Assessment
for each of the event categories in Table 1 that are expected to produce more severe System impacts within its planning area. [Violation Risk Factor:
High] [Time Horizon: Long-term Planning]

Proposed changes to Requirement R8
EEI suggests that subparts 8.1 and 8.2 should be placed under Requirement R4. In addition to this change the last sentence in R8 referencing those
subparts should be removed. See EEI comments to Requirement R4 below.

R8 Each responsible entity, as identified in Requirement R1, shall complete an Extreme Temperature Assessment of the Long-Term Transmission
Planning Horizon at least once every five calendar years, using the benchmark planning cases and the System models identified in Requirement R3
and R4, and the Contingencies identified in Requirement R7 for each of the event categories in Table 1, and document assumptions and results of the
steady state and stability analyses. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]

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Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

No

Document Name
Comment
Our SMEs only over-arching concern with R’s 3-8 are regarding potential discrepancy between TPL-008 and TPL-001 results. As far as I’m aware TPL001 requires the evaluation of “peak load” and does not require a determination of how “extreme” this condition is. If the ERO’s TPL-008 Benchmark
event results in the derived TPL-008 case(s) being less stressful than an entity’s TPL-001 assessment are TPL-001 Corrective Action Plans generated
from non P0/P1 events invalidated?
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Michele Tondalo - United Illuminating Co. - 1
Answer

No

Document Name
Comment
My only over-arching concern with R’s 3-8 are regarding potential discrepancy between TPL-008 and TPL-001 results. As far as I’m aware TPL-001
requires the evaluation of “peak load” and does not require a determination of how “extreme” this condition is. If the ERO’s TPL-008 Benchmark event
results in the derived TPL-008 case(s) being less stressful than an entity’s TPL-001 assessment are TPL-001 Corrective Action Plans generated from
non P0/P1 events invalidated?

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Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza
Answer

No

Document Name
Comment
•

Regarding R3 and R4—it is not clear what the difference is between “planning cases” (R3) and “system models” (R4). These are not defined in
the NERC glossary, and their use here should be clarified.

•

Regarding R5, FAC-014-3 R6 requires Planning Coordinators and Transmission Planners to use facility ratings, voltage and stability limits that
are equal or more limiting than its respective Reliability Coordinators. Presumably this is intended to give PCs/TPs more leeway in criteria for
extreme events, but unless some exception is made for FAC-014-3 R6, there may be no further room possible (particularly if the ordinary
planning limits are equal to the operational limits, which is probably typical).
R7 should clearly indicate which contingency categories are required.
R4, R5, R6, R7 and R8: “Responsible entity” should be defined in the Applicability section or should replaced with “Each Planning Coordinator,
in conjunction with its Transmission Planner(s)...” ). Suggest to replace 4.1 to “Responsible Entity” instead of “Functional Entity”.
R6: please complete the phrase“….to identify instability, uncontrolled separation, or Cascading”. For example, are we identifying instability,
uncontrolled separation, or Cascading of the System? The Interconnection? If that is the case, we suggest to specify “to identify instability,
uncontrolled separation, or Cascading of the System” or “to identify instability, uncontrolled separation, or Cascading Interconnection”.

•
•
•

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Richard Vendetti - NextEra Energy - 5
Answer
Document Name
Comment
R3-Yes,

R4-Yes,

R5- Yes,

No

R6- “Due to the potential impact of thermal overloads that could require load drops but do not result in instability or cascading, entities should be
required to establish acceptable load drop limit thresholds for addressing thermal overloads identified before utilizing non-consequential load drops as a
corrective action plan.

R7- “Due to the prevalence of stuck breaker conditions and their impacts during extreme cold conditions, corrective action plans should be required for
stuck breaker conditions resulting in voltage violations, thermal violations (beyond load drop limit), or cascading.

R8 – Yes, but comments for R6 & R7 should be addressed.

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Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer

No

Document Name
Comment
LG&E and KU agrees with EEI's comments.
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Response
Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

No

Document Name
Comment
R3 requires Planning Coordinator (PC) to develop and implement a process to coordinate the development of benchmark planning cases but the
benchmark event likely impacts the transmission system beyond the PC’s planning area. The planning cases would not be modeled correctly if it only
includes the system conditions within the PC’s area alone. The responsibility of coordinating and developing the models is well beyond the entity’s
alone. At a minimum, the Reliability Coordinator (RC) area should be included in the coordination and development process and the event can reach
well beyond the RC area.
R4 requires the maintenance of the system models for performing the assessment. If the models have to be developed and coordinated on a regional
basis and other entities need to perform the assessment at a different time or year (minimum once every 5 years), the requirement is not clear on the

responsibility of the entity in developing and providing the extreme weather models to other entities for the year(s) that the assessment is required to be
performed for the entity itself.
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Kristine Martz - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment
EEI does not agree with the language contained in requirements R3, R4, R7, and R8 for the reasons expressed below. (See the proposed changes in
boldface to Requirement R3 below)
Proposed changes to Requirement R3:
1. EEI suggests it would be clearer to replace “impacted” with adjoining or neighboring Planning Coordinators since they would be the only impacted
PCs.
2. EEI also suggests some changes to the subparts of Requirement R3 to better clarify the required tasks under the PC process.
R3. Each Planning Coordinator shall develop and implement a process for coordinating the development of benchmark planning cases among
adjoining Planning Coordinator(s), Transmission Planner(s), and other designated study entities under their purview to ensure benchmark events as
identified in Requirement R2 are coordinated. This process shall include: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
3.1.

Review of the planning study area boundaries under each Transmission Planner to ensure study completeness.

3.2. Verification that the benchmark planning cases include seasonal and temperature dependent adjustment for Load, generation, Transmission,
and transfers which represents the selected benchmark events.

Proposed revisions to Requirement R4
EEI suggests the subparts of Requirement R8 are better placed under Requirement R4 with the edits suggested below:
R4. Each responsible entity, as identified in Requirement R1, shall develop and maintain System models within its planning area for performing the
Extreme Temperature Assessment. The System models shall use data consistent with that provided in accordance with the MOD-032 standard,
supplemented by other sources as needed. System models shall be developed for the following conditions: [Violation Risk Factor: High] [Time
Horizon: Long-term Planning]
4.1 System conditions based on each benchmark event selected in Requirement R2 for one of the years in the Long-Term Transmission
Planning Horizon.
4.2 For each of the models developed for Requirement R4 Part 4.1, a sensitivity analysis shall be performed to demonstrate the impact of
changes to the basic assumptions used in the model. To accomplish this, the sensitivity analysis shall include, at a minimum, changes to
one of the following conditions:

·

Generation,

·

Real and reactive forecasted Load, or

·

Transfers.

Proposed change to Requirement R7:
EEI disagrees with including a requirement to have a documented rationale for the Contingencies selected because it represents an unnecessary
administrative burden.
R7. Each responsible entity, as identified in Requirement R1, shall identify the Contingencies used in performing the Extreme Temperature
Assessment for each of the event categories in Table 1 that are expected to produce more severe System impacts within its planning area. [Violation
Risk Factor: High] [Time Horizon: Long-term Planning]

Proposed changes to Requirement R8
EEI suggests that subparts 8.1 and 8.2 should be placed under Requirement R4. In addition to this change the last sentence in R8 referencing those
subparts should be removed. See EEI comments to Requirement R4 below.
R8. Each responsible entity, as identified in Requirement R1, shall complete an Extreme Temperature Assessment of the Long-Term Transmission
Planning Horizon at least once every five calendar years, using the benchmark planning cases and the System models identified in Requirement R3
and R4, and the Contingencies identified in Requirement R7 for each of the event categories in Table 1, and document assumptions and results of the
steady state and stability analyses. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]

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Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

No

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and Midwest Reliability Organization's NERC
Standards Review Forum (MRO NSRF) on question 4
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0

Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst Ballot
Body Member and Proxies
Answer

No

Document Name
Comment
Under R6 and the Table 1 Stability Performance Criteria, does the SDT intend for dynamic stability simulation to be required to identify instability,
uncontrolled separation, or Cascading consistent with the April 14, 2023 NERC report developed for Project 2023-06 CIP-014? Does the SDT intend for
responsible entities to be required to run dynamics for all contingencies, or would for entities be permitted to develop criteria to identify a subset of
contingencies for dynamic analysis? RF recommends the drafting team coordinate with the Project 2023-06 CIP-014 Risk Assessment Refinement
drafting team to ensure that any best practices being developed by that team in support of drafting a standard to effectively require consistent and
effective approaches for evaluating instability, uncontrolled separation, or Cascading are applied in drafting TPL-008.
Additionally, RF is concerned that R8 may not provide enough specificity regarding the time frame to be assessed from the Long-Term Transmission
Planning Horizon. Does the SDT intend every year in the horizon to be studied at least once every five calendar years or one year in the horizon to be
selected for study (e.g., TPL-001-5.2 R2 Part 2.2.1)?
Lastly, R8 Part 8.2 states that the Extreme Temperature Assessment shall include, at a minimum, changes to one of the following conditions:
Generation; Real and reactive forecasted Load; or Transfers. RF is concerned that the assessment should not just consider one of the listed conditions
but all of the listed conditions.
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Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer

No

Document Name
Comment
MPC supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
Likes

1

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Lakeland Electric, 1, Watt Larry
0

Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Document Name
Comment

No

Dominion Energy supports EEI comments. In addition, the expectations of what these cases will look like and just how they must be developed is not
well-defined in R4.
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Joshua London - Eversource Energy - 1, Group Name Eversource
Answer

No

Document Name
Comment
R3: Eversource disagrees with the use of the word “impacted” in the following phrase “impacted Planning Coordinator(s), Transmission Planner(s), and
other designated study entities…” Eversource suggests using the term “adjacent” as found in other planning standards. If other impacted entities want
this information, they can request the entire assessment via R11.
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Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

No

Document Name
Comment
For R3, Oncor agrees with the idea that the PC should have the responsibility for coordinating and developing benchmark planning cases.
For R4, “Each responsible entity…” could be replaced with language that is similar to R3, and it would instead read “Each Planning Coordinator….”
For R5, Oncor urges its comment from R4, particularly because the PC would develop and maintain the criteria for acceptable System steady state
voltage limits and post-Contingency voltage deviations.
For R6, Oncor urges its comment from R5. The PC would need to ensure that all entities use the same methodology and criteria for instability,
uncontrolled separation, or Cascading.
For R8, Oncor asks whether language can be added to ensure that entities can take credit for studies that are run as part of the Extreme Temperature
Assessment rather than running those studies again as part of the assessment to be conducted under TPL-001? For example, the Extreme
Temperature Assessment could take the place of the sensitivity analysis required within the TPL-001 assessment.
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Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

No

Document Name
Comment
Minnesota Power supports MRO’s NERC Standards Review Forum’s (NSRF) comments.
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Lenise Kimes - City and County of San Francisco - 1,5 - WECC
Answer

No

Document Name
Comment
·
• R3 - The responsibility is assigned to “each PC,” but the weather events selected from the ERO library will certainly cross multiple PC footprints in
almost every case. This argues for the development of regional processes and the development of base cases that could be used by multiple PC
entities. Regional planning groups or the regional entities (such as WECC) may be better groups for developing these processes and base cases than
the PC.
o As currently written, R3 does not appear to preclude PCs from working together on this requirement. Does the drafting team envision this as an
acceptable way to meet R3?
o If so, an alternative wording might be: Each Planning Coordinator shall coordinate with other impacted Planning Coordinator(s), Transmission
Planner(s), and other designated study entities to develop and implement joint and/or individual processes for coordinating the development of
benchmark planning cases based on the selected benchmark events as identified in Requirement R2.

• R4 - It would be helpful if this requirement (or other NERC guidance for this requirement) would provide additional details on what additional
system models (e.g., steady state and stability) are required and how the required modeling data differs from the current MOD-032 and TPL-001
requirements. There may also be some data requirements for the Extreme Temperature Assessment that are not addressed by the current version of
MOD-032, such as special high/cold temperature Facility Ratings, generation de-rating and dispatch patterns, or climate change forecasts that could
impact the temperature assumptions for load models. Since MOD-032 does not currently address these data requirements, they need to be addressed
in TPL-008 as an appendix, in a Guidelines and Technical Basis section, or in a future modification to MOD-032 itself.

• R5 - As with TPL-007 and TPL-001, it appears that the study criteria are set by the “responsible entity” which is negotiated under R1. While the
responsible entity is charged with maintaining system reliability, the criteria will also determine the number of CAPs and amount of transmission
investment that are required to meet TPL-008. TPL-001-5.1 is already triggering the need for additional transmission investment over the coming years,
so TO/GO entities that will actually pay for the upgrades will be further taxed by TPL-008. The implementation plan needs to be long enough so that the
investments for TPL-008 do not coincide closely with the TPL-001-5.1 implementation period.

• R5 – This requirement states that the responsible entity “shall have criteria” while R6 states that the responsible entity “shall define and document
criteria?” The wording in R6 appears to be better, since both sets of criteria should be “defined and documented” in each Extreme Temperature
Assessment report. It is suggested that the wording from R6 be used for R5.

• R6 - Instability criteria are generally not “adjustable” limits. That is, the system is either unstable or it is not. If the events in the ERO library are too
severe and lead to a significant increase in the events that trigger instability, these could be expensive problems to fix. See comments for R2.

• R7 - It would be helpful to see this requirement address the differences between the set of contingencies for TPL-001 rather than an absolute set
- this provides more value for all entities rather than showing a largely duplicative full set of outages.

• R7 - P5 events are already very unlikely since they require a fault event plus an equipment failure, which is essentially a multiple outage on par
with the likelihood of a P6 event (which is excluded from this standard). The Extreme Temperature event benchmark cases are very unlikely extreme
events to begin with (and an extreme sensitivity to the TPL-001 studies), which further reduces the likelihood of having a P5 event during an Extreme
Temperature event. In addition, the severity of significant P5 events strongly suggests upgrades will already be identified by the annual Assessment
required by TPL-001.
o Given the amount of work already added by this standard, the low likelihood of the P5 events on par with other excluded events from TPL-001 (such
as P6), and the strong likelihood that impacts from these events are already adequately captured by the TPL-001 Assessment studies, we strongly
recommend removing P5 events from Table 1 of TPL-008.
• R8 - While it is a helpful limitation to only require one assessment year from the Long-Term Planning Horizon, this may not be practicable for the
development of CAPs that involve capital investment as these projects require multiple years to permit and construct. The CAPs that involve capital
investment will need to be reviewed and refined as the potential violations move into the Near-Term Planning Horizon and prior to the operating
horizon. TPL-001 studies will not include the conditions and criteria required to address these studies, so separate Extreme Temperature event
benchmark cases will need to be developed for the Near-Term Transmission Planning Horizon to address these cases.
• R8 - Especially for the very first Extreme Temperature Assessment, it is possible that a large number of CAPs may be identified for criteria
violations that already exist in the Near-Term Planning Horizon. This will create a backlog of projects which will need to be started immediately to meet
the implementation plan period. These projects will be on top of the P5 projects that are already backlogged for implementation of TPL-001-5.1.
o It is recommended that the implementation plan allow a ten-year period for implementation of CAPs that require capital investment to construct new
facilities. This would also match up well with performing these studies for the Long-Term Transmission Planning Horizon since the studied case could
be a ten year case.

• R8.2 - Sensitivity to generation, load and transfers are already studied as part of TPL-001-5.1. The sensitivity additional studies proposed for
R8.2 are unlikely to yield any new information and will be duplicative work for Transmission Planners. The Extreme Temperature Assessment is

already a very extreme sensitivity study itself that should already capture modified load, generation, transmission, and transfers befitting this analysis
per R3, so it is not needed nor appropriate to study sensitivities for sensitivity cases.
o R8.2 should be removed entirely to reduce unnecessary workload which will provide information that is duplicative and provide no additional value
since the studies under this standard are already in effect sensitivities in comparison to the Assessment studies under TPL-001.
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Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer

No

Document Name
Comment
The approval process for benchmark assessments is not clearly defined or mentioned so clarity would be needed there. “Extreme” weather will differ
across the geographical footprints and in some cases across an individual TP/PCs footprint. There may be a need to consider impacts within areas of a
TP/PCs footprint which may complicate issues but would reflect risks. While Requirement 3.1 appears to capture the thought, are mechanisms in place
in planning study tools to accommodate the approach?
The phrase “other designated study entities” is unclear in Requirement R3. How will the parameters be limited (in terms of bandwidth) to allow planning
to occur that “represents” the benchmark case? There are no limits as to how many benchmark cases will be developed and could be as simple as 2
(one cold and one hot weather). Is it clear that the benchmark cases will not exactly match the conditions that may need studied but if the flexibility in
use is so broad, the benchmark event quality of the assessment could be lost. Requirement 4 – Is that already covered in TPL-001 (develop and
maintain)? Requirement 5, Requirements 5, 6, and 7 appears to be very similar to Requirements R5 and R6 in TPL-001-5. In essence the language in
R5/R6/R7 may be partially if not wholly duplicative of language in TPL-001-5 and the SDT should consider removal of the requirements and explain
what is expected in the Technical Rationale. Requirement 8 sensitivity seems to be limited and may not reveal cases where the extreme weather
conditions impose critical reliability issues. Are the sensitivities limited to the “boundary” as called out in Requirement R3.1?
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Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

No

Document Name
Comment
Stability expectations unclear and needs clarification for which sorts of analyses are expected (angular, voltage, freq). Language is similar to TPL-007
but should be more bases on TPL-001.Since this is for wide events,PC should be responsible, not TP.

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Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

No

Document Name
Comment
The Standard Drafting Team should clarify how much coordination is required among neighboring PCs. Does “coordination” mean that neighboring
PCs must choose the same benchmark event? If the planned study area boundary bisects a PC’s planning area, does that PC have to do two
benchmark planning cases?
Extreme weather events involve a large geographical area that extends beyond most PCs’ footprints, so coordination among “impacted PCs” will be
complicated and difficult. It will also be challenging to identify “impacted PCs” without the planning cases and Extreme Temperature
Assessment. Using “adjacent PCs” is more practical.
For Requirement R8.2, requiring sensitivity studies on top of the new extreme weather events is extensive and unnecessary.
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Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA recommends extreme benchmark events be evaluated for their impact in a larger region than just the TP/PC area. Regional Entities are better
situated to select base cases and perform assessments in collaboration with the utilities in the region. Thus, utilities will be better suited to consider
mitigation plans in their system based on existing criteria, TPL-001-5.
BPA recommends the P0 base case include all transmission lines in service. While there could be transmission outages, particularly during extreme
cold storms, these are addressed in the Operating Horizon by developing and implementing operating plans. Additionally, BPA seeks clarity on how the
PC can justify why it selected one set of outages versus another, thereby setting the PC up for a potential compliance failure.
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Leslie Hamby - Southern Indiana Gas and Electric Co. - 3,5,6 - RF
Answer

No

Document Name
Comment
R3: For R3, Southern Indiana Gas & Electric Company d/b/a CenterPoint Energy Indiana South (SIGE) recommends adding “adjacent” before
“impacted” as illustrated below:
R3. Each Planning Coordinator shall develop and implement a process for coordinating the development of benchmark planning cases among adjacent
impacted Planning Coordinator(s), Transmission Planner(s), and other designated study entities based on the selected benchmark events as identified
in Requirement R2…

R5: For R5, SIGE requests clarification as to how the criteria for “steady state voltage limits and post-Contingency voltage deviations” under TPL-008,
R5 differs from what entities have defined under TPL-001-5.1. SIGE has concerns that R5 may duplicate work already occurring under TPL-001-5.1.

R7: For R7, SIGE recommends revisions to align with R3.1 as well as strike the last sentence of R7. Recommend revisions are illustrated below:
R7. Each responsible entity, as identified in Requirement R1, shall identify Contingencies used in performing the Extreme Temperature Assessment for
each of the event categories in Table 1 that are expected to produce more severe System impacts within its planning study area boundary defined in
Part 3.1.
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Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
Please refer to Question 1 comments.
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Adrian Andreoiu - BC Hydro and Power Authority - 1, Group Name BC Hydro
Answer

No

Document Name
Comment
BC Hydro appreciates the drafting team's efforts and the opportunity to comment.
1. Requirements R3 & R4: Individual PCs and TPs having to conduct Extreme Temperature Assessments may find these requirements burdensome.
As extreme weather events may encompass multiple PC Areas, and depending on the information available in conjunction with benchmark events, the
entity identification, benchmark planning cases and system models development and study assumptions can pose significant challenges.
At this stage of development it does not seem clear which entity(ies) will select most appropriate Events for study and how appropriate study basecases
are to be created and eventually coordinate the study.
BC Hydro requests that the drafting team clarify obligations among the required entities, and BC Hydro suggests that a Regional Coordinator, such as
Regional Reliability Organizations may be more suitable to take an active role in identifying the Events for study, and developing planning study cases
that involve multiple PCs within their area. This approach is similar to TPL-007, where WECC collects data from PCs and creates planning cases for
use in the PC’s studies.
2. Requirement R4 references MOD-032. Given the expanded scope of data models for the Extreme Temperature Assessments, the current MOD032 data model specifications may not be adequate.
3. Requirement R8 mandates that entities conduct Extreme Temperature Assessments for both benchmark planning cases (Part 8.1) and sensitivity
cases (Part 8.2). Given that extreme weather benchmark planning cases already encompass system conditions during extreme heat or extreme cold
events, the benchmark extreme weather planning study may inherently serve as a sensitivity study in addition to the standard TPL-001-5 transmission
planning assessment.
4. While recognizing the direction in FERC Order 896 to require sensitivity analyses, there does not seem to be an evaluation statistical/probabilistic
or otherwise to inform the selection of adequate contingency and sensitivity scenarios that would lead to a measurable and improved outcome.
BC Hydro appreciates the Technical Rationale discussion and considerations vis-à-vis the FERC Order 896 directive, and suggests that additional
analysis or other supporting documentation will be beneficial to further substantiate the required assessment methodology.
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Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer

No

Document Name
Comment
Consumers Energy agrees with the comments and suggestions from EEI:

EEI does not agree with the language contained in requirements R3, R4, R7, and R8 for the reasons expressed below. (See the proposed changes in
boldface to Requirement R3 below)
Proposed changes to Requirement R3:
1.
EEI suggests it would be clearer to replace “impacted” with adjoining or neighboring Planning Coordinators since they would be the only impacted
PCs.
2.

EEI also suggests some changes to the subparts of Requirement R3 to better clarify the required tasks under the PC process.

R3. Each Planning Coordinator shall develop and implement a process for coordinating the development of benchmark planning cases among
adjoining Planning Coordinator(s), Transmission Planner(s), and other designated study entities under their purview (remove: based on the selected) to
ensure benchmark events as identified in Requirement R2 are coordinated. This process shall include: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
3.1.
(Remove: Define the) Review of the planning study area (remove: boundary) boundaries under each Transmission Planner, (remove: based) to
ensure study completeness.
3.2. Verification that (remove: Modify) the benchmark planning cases (remove: to) include seasonal and temperature dependent adjustment for Load,
generation, Transmission, and transfers which represents the selected benchmark events.
Proposed revisions to Requirement R4
EEI suggests the subparts of Requirement R8 are better placed under Requirement R4 with the edits suggested below:
R4. Each responsible entity, as identified in Requirement R1, shall develop and maintain System models within its planning area for performing the
Extreme Temperature Assessment. The System models shall use data consistent with that provided in accordance with the MOD-032 standard,
supplemented by other sources as needed (remove:, and shall represent projected System conditions based on the selected benchmark events as
identified in Requirement R2). System models shall be developed for the following conditions: [Violation Risk Factor: High] [Time Horizon: Long-term
Planning]
4.1 System conditions based on each benchmark event selected in Requirement R2 for one of the years in the Long-Term Transmission Planning
Horizon.
4.2 For each of the models developed for Requirement R4 Part 4.1, a sensitivity model shall be developed to demonstrate the impact of changes to the
basic assumptions used in the model. To accomplish this, the sensitivity model shall include, at a minimum, changes to one of the following conditions:
Generation, Real and reactive forecasted Load, or Transfers.
Proposed change to Requirement R7:
EEI disagrees with including a requirement to have a documented rationale for the Contingencies selected because it represents an unnecessary
administrative burden.
R7. Each responsible entity, as identified in Requirement R1, shall identify the Contingencies used in performing the Extreme Temperature
Assessment for each of the event categories in Table 1 that are expected to produce more severe System impacts within its planning area. (Remove:
The rationale for those Contingencies selected for evaluation shall be available as supporting information.) [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
Proposed changes to Requirement R8
EEI suggests that subparts 8.1 and 8.2 should be placed under Requirement R4. In addition to this change the last sentence in R8 referencing those
subparts should be removed. See EEI comments to Requirement R4 below.

R8 Each responsible entity, as identified in Requirement R1, shall complete an Extreme Temperature Assessment of the Long-Term Transmission
Planning Horizon at least once every five calendar years, using the benchmark planning cases and the System models identified in Requirement R3
and R4, and the Contingencies identified in Requirement R7 for each of the event categories in Table 1, and document assumptions and results of the
steady state and stability analyses. (Remove: The Extreme Temperature Assessment shall include the following.) [Violation Risk Factor: High] [Time
Horizon: Long-term Planning]
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Isidoro Behar - Long Island Power Authority - 1
Answer

No

Document Name
Comment
Regarding R3:
R3 requires the development of benchmark planning cases based on the selected benchmark events as identified in Requirement R2.
R3.2 states:
“The process shall… Modify the benchmark planning cases to include seasonal and temperature dependent adjustment for Load, generation,
Transmission, and transfers which represents the selected benchmark events.”
The intent of the phrase “modify the benchmark planning cases” and the overall intent of R3.2 is not entirely clear.
We recommend to clarify the wording of “modify the benchmark planning cases”, and R3.2 as a whole - such as:
“3.2 The process shall require that the benchmark planning cases reflect seasonal and temperature dependent adjustment(s) for Load, generation,
Transmission, and transfers that are representative of the selected benchmark events.”

In other words, the benchmark planning cases to be developed should reflect the adjustments specified in R3.2.

Regarding R4:
R4 mentions “shall represent projected System conditions based on the selected benchmark events as identified in Requirement R2”.
Question for SDT: is this phrasing consistent with (or redundant to) the wording in R3.2?

Regarding R3 and R4—it is not clear what the difference is between “planning cases” (R3) and “system models” (R4). These are not defined in the
NERC glossary, and their use here should be clarified.

Regarding R5, which states:
”Each responsible entity, as identified in Requirement R1, shall have criteria for acceptable System steady state voltage limits and post-Contingency
voltage deviations for performing the Extreme Temperature Assessment in accordance with Requirement R3.”
We believe the reference to Requirement 3 is misplaced. Recommend to either remove the reference to R3, or change to reference to R8 (which
specifies the completion of an Extreme Temperature Assessment).

Question for SDT: was thermal criteria intentionally omitted from R5?

Regarding Measure 5: We believe the reference to Requirement 5 is misplaced. Recommend to either remove the reference to R5, or change to
reference to R8 (which specifies the completion of an Extreme Temperature Assessment).

Regarding R5, FAC-014-3 R6 requires Planning Coordinators and Transmission Planners to use facility ratings, voltage and stability limits that are
equal or more limiting than its respective Reliability Coordinators.
Question for SDT: Does FAC-014-3 R6 still apply for the Extreme Temperature Assessment, or can the PC / TP choose less stringent criteria than the
criteria specified in the RC’s SOL methodology?

Regarding R7:
“Each responsible entity, as identified in Requirement R1, shall identify Contingencies used in performing the Extreme Temperature Assessment for
each of the event categories in Table 1 that are expected to produce more severe System impacts within its planning area. The rationale for those
Contingencies selected for evaluation shall be available as supporting information.”
Recommend to replace the term “event categories” with the term “planning events, to be more consistent with TPL-001-5.1 R3.4.

Regarding R8:
It is recommended to expand this requirement to clearly indicate that steady state and stability analyses are both required for the Extreme Temperature
assessment (for example, consider using the phrase “shall consist of steady state and stability analyses” ….).

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Ben Hammer - Western Area Power Administration - 1

Answer

No

Document Name
Comment
Please address the following in R3-R8:

R3 – Please clarify obligations on coordination with neighboring PCs to perform an Extreme Temperature Assessment. If the particular extreme heat or
extreme cold benchmark event is only applicable to a limited portion of a PC’s footprint (Part 3.1), verify that the PC has satisfied it obligation under R2
for completing an Extreme Temperature Assessment for either “one extreme heat benchmark event or one extreme cold benchmark event” for that fivecalendar year period (R8).

R4 – Revisit after benchmark event cases are available.

R5 – R5 may be duplicative of work being performed under TPL-005.1. How is the criteria for steady state voltage limits and post-Contingency voltage
deviations under TPL-008, R5 different than what entities have defined under TPL-001-5.1?

R6 - R6 may duplicate work that is already occurring under TPL-001-5.1, PRC-006, etc. or be excessive as found to be the case with Recommendation
#11 in the FERC-NERC Winter Storm Elliott Report. In that case, inertia and frequency data indicated Winter Storm Elliott was not a low inertia event;
but rather a shortage of generation event. As a shortage of generation event, Winter Storm Elliott no longer warrants the level of effort required to
conduct an inertia study. In lieu of a study, a report will be written to describe the analysis completed in support of the recommendation. Similarly,
Winter Storm Uri was tied to under-frequency load shed (UFLS) and UFLS design assessments performed pursuant to PRC-006.
Please justify the need for R6 by:
Describing where there have been extreme temperature events which have resulted in system instability, uncontrolled separation, or Cascading and
To consider providing planning entities with an “off-ramp” (e.g. written report) when analysis indicates an Extreme Temperature Assessment is not
warranted.
R7 – To clarify that the Extreme Temperature Assessment is limited to the planning study area boundary defined in Part 3.1., it is requested that the
SDT modify requirement R7 as follows:
R7. Each responsible entity, as identified in Requirement R1, shall identify Contingencies used in performing the Extreme Temperature Assessment for
each of the event categories in Table 1 that are expected to produce more severe System impacts within the planning study area boundary defined in
Part 3.1. The rationale for those Contingencies selected for evaluation shall be available as supporting information.
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Lakeland Electric, 1, Watt Larry
0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter

Answer

No

Document Name
Comment
FirstEnergy requests additional clarity on coordination when more than one PC/TP are impacted – basically the management of different processes
across PC/TP footprints.
In addition, FirstEnergy requests the Drafting Team look at the possibility of a responsible entity to have multiple benchmark cases for those footprints
that include differing extreme heat or extreme cold weather conditions in its single footprint of responsibility.
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Robert Follini - Avista - Avista Corporation - 3
Answer

No

Document Name
Comment
The area of impact is vague and should be clearly defined.
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Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

No

Document Name
Comment
Requirement 3.2 states that adjustments must be made for load, generation, transmission, and transfers. This will be a significant undertaking for
industry load forecasting entities, generator owners, and transmission owners to respond to information requests from the entities responsible for the
development of the benchmark planning cases (Planning Coordinators and Transmission Planners). It is recommended that NERC work with industry to
develop a guideline and best practices document to determine where reasonable approximations can be made without submitting information requests
to Distribution Providers, Generator Owners, and Transmission Owners.
It would be preferred if the ERO’s review of past events could be used to develop relatively simple recommendations for the PC/TP to use in their
extreme heat and extreme cold benchmarks. For example, the extreme cold event could consider a temperature 5C below historic maximum cold
weather events. The PC/TP should document their assumptions on expected generator availability and imports.

The PC/TP are in the best position to develop their own planning cases that reflect seasonal and temperature dependent adjustments to load,
generation and transfers. The planning study area boundary should be limited to the PC area in order to develop corrective action plans that have a
chance on being implemented. Neighbouring PCs should have an opportunity to review cases (optional) and study plans and assumptions so that the
availability of imports and generation can be modeled more accurately.
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Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

No

Document Name
Comment
Black Hills Corporation agrees with the proposed changes from EEI. 4.1 and 4.2 are better suited to be part of Requirement R4. Black Hills Corporation
agrees with EEI’s proposed changes to Requirements R7 and R8. This commentary from EEI is included below:
EEI does not agree with the language contained in requirements R3, R4, R7, and R8 for the reasons expressed below. (See the proposed changes in
boldface to Requirement R3 below)
Proposed changes to Requirement R3:
1.
EEI suggests it would be clearer to replace “impacted” with adjoining or neighboring Planning Coordinators since they would be the only impacted
PCs.
2.

EEI also suggests some changes to the subparts of Requirement R3 to better clarify the required tasks under the PC process.

R3. Each Planning Coordinator shall develop and implement a process for coordinating the development of benchmark planning cases among
adjoining Planning Coordinator(s), Transmission Planner(s), and other designated study entities under their purview (remove: based on the
selected) to ensure benchmark events as identified in Requirement R2 are coordinated. This process shall include: [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning]
3.1.
(Remove: Define the) Review of the planning study area (remove: boundary) boundaries under each Transmission Planner, (remove:
based) to ensure study completeness.
3.2. Verification that (remove: Modify) the benchmark planning cases (remove: to) include seasonal and temperature dependent adjustment for
Load, generation, Transmission, and transfers which represents the selected benchmark events.
Proposed revisions to Requirement R4
EEI suggests the subparts of Requirement R8 are better placed under Requirement R4 with the edits suggested below:
R4. Each responsible entity, as identified in Requirement R1, shall develop and maintain System models within its planning area for performing the
Extreme Temperature Assessment. The System models shall use data consistent with that provided in accordance with the MOD-032 standard,
supplemented by other sources as needed (remove:, and shall represent projected System conditions based on the selected benchmark events
as identified in Requirement R2). System models shall be developed for the following conditions: [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]

4.1 System conditions based on each benchmark event selected in Requirement R2 for one of the years in the Long-Term Transmission
Planning Horizon.
4.2 For each of the models developed for Requirement R4 Part 4.1, a sensitivity model shall be developed to demonstrate the impact of
changes to the basic assumptions used in the model. To accomplish this, the sensitivity model shall include, at a minimum, changes to one
of the following conditions:

•
•
•

Generation,
Real and reactive forecasted Load, or
Transfers.

Proposed change to Requirement R7:
EEI disagrees with including a requirement to have a documented rationale for the Contingencies selected because it represents an unnecessary
administrative burden.
R7. Each responsible entity, as identified in Requirement R1, shall identify the Contingencies used in performing the Extreme Temperature
Assessment for each of the event categories in Table 1 that are expected to produce more severe System impacts within its planning area. (Remove:
The rationale for those Contingencies selected for evaluation shall be available as supporting information.) [Violation Risk Factor: High] [Time
Horizon: Long-term Planning]
Proposed changes to Requirement R8
EEI suggests that subparts 8.1 and 8.2 should be placed under Requirement R4. In addition to this change the last sentence in R8 referencing those
subparts should be removed. See EEI comments to Requirement R4 below.
R8 Each responsible entity, as identified in Requirement R1, shall complete an Extreme Temperature Assessment of the Long-Term Transmission
Planning Horizon at least once every five calendar years, using the benchmark planning cases and the System models identified in Requirement R3
and R4, and the Contingencies identified in Requirement R7 for each of the event categories in Table 1, and document assumptions and results of the
steady state and stability analyses. (Remove: The Extreme Temperature Assessment shall include the following.) [Violation Risk Factor: High]
[Time Horizon: Long-term Planning]
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Michael Whitney - Northern California Power Agency - 3, Group Name NCPA
Answer
Document Name
Comment

No

NO, These assessment should be performed by the Regional Entities. There appears to be too much room for coordination issues having one
Transmission Planner (TP) or Planning Coordinator (PC) having to rely on other TPs or PCs to meet their requirement deadlines.
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Lauren Giordano - Lauren Giordano On Behalf of: Dennis Sismaet, Northern California Power Agency, 4, 6, 3, 5; Marty Hostler, Northern
California Power Agency, 4, 6, 3, 5; Michael Whitney, Northern California Power Agency, 4, 6, 3, 5; - Lauren Giordano
Answer

No

Document Name
Comment
NO, These assessment should be performed by the Regional Entities. There appears to be too much room for coordination issues having one
Transmission Planner (TP) or Planning Coordinator (PC) having to rely on other TPs or PCs to meet their requirement deadlines.
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Jessica Cordero - Unisource - Tucson Electric Power Co. - 1 - WECC
Answer

No

Document Name
Comment
R3: No. This requirement doesn’t put boundaries on adjacent entities for requesting unlimited cases. Proposed language: “Each PC shall develop and
implement a process for development of benchmark planning cases among entities within its PC Area based on the benchmark events
selected in Requirement R2. This process shall:
3.1 (no change)
3.2 (no change)
R4-R6: No. The issue is with double jeopardy with TPL-001-5.1 not the language since it is already included as a similar requirement in TPL-001-5. No
problem if this is in a single standard.
R7: Yes but should specify P0, P1, P2, P4, P5, P7 not refer to events in Table 1 of this standard. Table 1 is used to commonly refer to Table 1 of TPL001-5 and the incomplete list of Planning Events can be confusing.
R8: No. Eliminate subrequirement 8.2. Sensitivity analysis is overly burdensome for an extreme weather scenario. We are already looking at unusual
circumstances and now adding more on top of it with generation, load, or transfer changes.

Documenting assumptions and results is separate from performing analysis and should be in different requirements.
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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
We can agree with the majority of the requirements. However, we are unable to agree with the concept of a sensitivity analysis for an extreme scenario
as likely contemplated by the benchmark scenarios required. As noted previously, we are unable to agree with R2 due to lack of clarity. Accordingly, we
are not able to agree with R8.2, suggesting that a sensitivity analysis may be required to be performed in addition to what is likely to be an excessively
extreme scenario, as determined by the extreme temperature assessment. This requirement seems to suggest we assess an extreme scenario in
addition to the extreme scenario.
In summary, there is a current lack of detail about how the extreme weather event base cases will be constructed. The information is not present in
either the standard or guidance document. Due to this lack of detail there are several possible objections to how the cases might be put together.
For example, since the study is already required to consider the contingencies listed in the Table 1, the extreme weather event base cases should only
consider total system load and generation dispatch but not any additional transmission outages that were occurring at the time of the event.
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Lakeland Electric, 1, Watt Larry
0

Response
Thomas Foltz - AEP - 5
Answer

No

Document Name
Comment
While it is reasonable to allow five years for both preparing-for and conducting a “first time study”, as well as for the frequency of updating benchmark
data, we believe three years would be reasonable for conducting the subsequent studies. Refining those studies to properly reflect changes in system
topology and connected generation equipment would not likely require five years, so the team may wish to consider a three-year frequency instead.
AEP disagrees with the proposed inclusion of load shed in the obligations of TPL-008. AEP believes that the Transmission system should be designed
to securely operate at N-1 conditions and avoid preemptive load shed that would occur for secure operations. If load shed remains in the standard, it
should be allowed only for conditions more stringent than N-1 conditions. We believe this opinion is supported by the observations made in FERC Order
896.

Likes

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Lakeland Electric, 1, Watt Larry
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Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

No

Document Name
Comment
TPL-008-1 R3 uses the term “impacted”, while TPL-001-5.1 uses “adjacent” under R3.4.1 and R4.4.1. TPL-008-1 R3 also includes “other designated
study entities”, which is vague on the intent of this statement. “Impacted” is not a clear term for this requirement because one will not know who is
impacted until a study is performed. Similarly, but on the opposite spectrum of the risk, one may have adjacent entities that one determines are not
“impacted” and thus are not involved. It is better to have adjacent entities able to speak in to a process, whether or not a certain process determines
they are impacted.
We recommend the statement “other designated study entities” be removed from R3. For example, “Each Planning Coordinator shall develop and
implement a process for coordinating the development of benchmark planning cases among adjacent Planning Coordinator(s), and Transmission
Planner(s) based on the selected benchmark events as identified in Requirement R2”.
R8 is not clear using the term “sensitivity”. TPL-001-5 more clearly calls out which cases and types of analysis are required for the sensitivity. From the
existing language, it is unclear if applying the sensitivity to extreme heat OR extreme cold is sufficient, or if this should be extreme heat AND extreme
cold. Similarly, is it steady state OR stability, or steady state AND stability? For example, “The sensitivity analysis should be run for each of the extreme
heat and extreme cold event assessments, both for the steady state and transient stability portions of the assessment”. In this manner, the expectation
is clear as to the scope of the sensitivity work.
In Order 881, the topic of ratings has become of interest for operations. A potentially beneficial sensitivity option not currently included would be a
sensitivity of ratings. For example, assuming a higher temperature as input to the planning ratings. Such an additional sensitivity could be beneficial in
helping entities better understand such relationships.
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Lakeland Electric, 1, Watt Larry
0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer

No

Document Name
Comment
Regarding R3 and R4—it is not clear what the difference is between “planning cases” (R3) and “system models” (R4). These are not defined in the
NERC glossary, and their use here should be clarified.

Regarding R5, FAC-014-3 R6 requires Planning Co-ordinators and Transmission Planners to use facility ratings, voltage and stability limits that are
equal or more limiting than its respective Reliability Co-ordinators. Presumably this is intended to give PCs/TPs more leeway in criteria for extreme
events, but unless some exception is made for FAC-014-3 R6, there may be no further room possible (particularly if the ordinary planning limits are
equal to the operational limits, which is probably typical).

R7 should clearly indicate which contingency categories are required.
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1

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Lakeland Electric, 1, Watt Larry
0

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Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
Please Provide clarity in the difference between benchmark planning cases mentioned in R3 and system models mentioned in R4. R8 seems to use
these interchangeably.
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Response
Kevin Conway - Western Power Pool - 4
Answer

No

Document Name
Comment
As R1 currently reads, only the Planning Coordinator is responsible for compliance.
The study boundary definition needs clarity. How is it defined? Is it fixed? Does it vary by Extreme Event?
For the setup of the base cases, is this a Mod 032 approach in that the gens/loads/transfers would be modeled in to match the conditions of the
historical event and then outages be taken on that case? It is unclear if a generator that went out due to the extreme weather event in real-time would
be modeled as in or out of service in the reference/benchmark case.
What if you and your neighbors disagree on the Event? The boundary? Etc.
Under R3 There’s some debate about what a “Benchmark” case represents, since it’s not very well defined. Transmission Planners are unsure what R3
requires them to do: Does this include modeling all generation outages, or not? Our interpretation is to adjust things based on temperature; if a

generator cannot operate at “x” temperature, because it’s too hot or too cold, then it should be off. If the pipeline freezes up and can’t provide fuel at “x”
temperature, you have plan for generator outages and should model it as such.
In reference to R4, citing MOD-032 is not a good practice in standards writing. It is possible that MOD-032 could be rewritten, superseded, or retired
and that would negatively affect this proposed standard. Perhaps the wording should be modified to state that "The System models shall use data
consistent with that provided in accordance with accepted Power System Modeling standards, supplemented by other sources as needed..."
In R5, shouldn't the Planning Coordinator ensure all entities are using the same criteria for acceptable System steady state voltage limits? If each entity
uses something different then these studies are not fully coordinated, and it is the functional responsibility to coordinate these types of studies.
R6 has the same flaw that R5 has. The responsible entities need to meet criterion that the Planning Coordinator sets, not what is in its own best
interest.
R7 must still be coordinated with the Planning Coordinator and should include both internal and external contingencies. Some entities may try and limit
contingencies to what gives them the most manageable performance. Again, the Planning Coordinator must make sure there is consistency across all
of the Transmission Planners in its area.
In R8 the need for each entity to complete an Extreme Temperature Assessment seems to duplicate work, when the Transmission Planners should be
providing data to the Planning Coordinator and having them do it for the entire footprint. This also does not allow smaller entities to collaborate and
combine resources to address a larger footprint. R8 does not address changes to assumptions once an assessment is done, nor does it address
changes in the extreme heat benchmark events and extreme cold benchmark events, from the approved benchmark library maintained by the Electric
Reliability Organization (ERO).
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Lakeland Electric, 1, Watt Larry
0

Response
Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer

Yes

Document Name
Comment
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0

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0

Response
Carver Powers - Utility Services, Inc. - 4
Answer
Document Name
Comment

Yes

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0

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0

Response
Israel Perez - Israel Perez On Behalf of: Mathew Weber, Salt River Project, 3, 1, 6, 5; Matthew Jaramilla, Salt River Project, 3, 1, 6, 5; Thomas
Johnson, Salt River Project, 3, 1, 6, 5; Timothy Singh, Salt River Project, 3, 1, 6, 5; - Israel Perez
Answer

Yes

Document Name
Comment
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0

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0

Response
Apollonia Gonzales - PNM Resources - 1,3 - WECC,Texas RE
Answer

Yes

Document Name
Comment
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0

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0

Response
Mark Flanary - Midwest Reliability Organization - 10
Answer

Yes

Document Name
Comment
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0

Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
Comment
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE has the following comments:
•
•

Requirement R3 includes “other designated study entities” in the requirement language, but is not clear who these “other designated study
entities” are. Please clarify.
In Requirement R5, Texas RE recommends stating an acceptable deviation range or by including ‘acceptable based on common industry
practice or technical basis as it is currently open-ended as to what criteria is “acceptable” for System steady state voltage limits and postContingency voltage deviations. Having a criteria would lead to more consistent application and oversight.

The provided Technical Rationale notes that, “The establishment of these criteria allows auditors to compare the results of the assessment with the
established criteria.” Texas RE is concerned, however, this could lead to an entity setting its criteria too broadly (allow for too much deviation) and
circumvent the intent Requirement R5.
•

In Requirement Part 8.2, Texas RE recommends adding the following language: “Justification for the particular condition changes to the
Sensitivity analysis should be included.”

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Alison MacKellar - Constellation - 5
Answer
Document Name
Comment
Constellation has no comments

Alison Mackellar on behalf of Constellation Segments 5 and 6
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Kimberly Turco - Constellation - 6
Answer
Document Name
Comment
Constellation has no comments
Kimberly Turco on behalf of Constellation Segments 5 and 6
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0

5. Do you agree with the proposed TPL-008-1 Reliability Standard Requirements R9 – R10 (CAPs and possible actions)? If you do not agree,
please provide your recommendation and, if appropriate, technical or procedural justification.
Kevin Conway - Western Power Pool - 4
Answer

No

Document Name
Comment
The requirements for Corrective Action Plans, as discussed in R9 and R10, fail to have any associated detail regarding expectations, plan approvals
and validation of completion. Maybe the Drafting Team should consider Mitigations rather than Corrective Action Plans, since the entity is trying to
mitigate future problems through operation actions, construction or technology.
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0

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0

Response
Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
Transmission projects developed and constructed to meet R9 will quickly be invalidated. GIA and TSR studies will not include these extreme
temperature assessments, resulting in the additional capacity that was built (at retail ratepayers' expense) to improve reliability in extreme
circumstances being reallocated to allow generators to deliver power across the transmission system.
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1

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Lakeland Electric, 1, Watt Larry
0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

No

Document Name
Comment
R10 - We can write-up recommendations but as as a Transmission Planner we don't have the authority,
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0

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0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer

No

Document Name
Comment
R9 indicates that CAPs should be developed “…when the benchmark planning case study results indicate the System is unable to meet performance
requirements…” but it is not clear whether the sensitivity analysis is included in “benchmark planning case study results”. For comparison, TPL-001-5.1
states that “Corrective Action Plan(s) do not need to be developed solely to meet the performance requirements for a single sensitivity case….” Should
something similar be stated in TPL-008, or is the intent that any case or sensitivity performance violation should trigger a CAP?

Additionally, R9 requires that “The responsible entities shall share their CAPs with, and solicit feedback from, applicable regulatory authorities or
governing bodies responsible for retail electric service issues.” This is unique to this standard and should be removed.
Likes

1

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Lakeland Electric, 1, Watt Larry
0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

No

Document Name
Comment
It is unclear if CAPs are required for sensitivity deficiencies. TPL-001-5.1 addresses such things in R2.7.2, however TPL-008-1 does not. In addition, it
is unclear if the sensitivity needs to be run on each R2/R4 case, or only one case. Again, TPL-001-5.1 uses clearer language in R2.1.3.
During the 04/12/2024 Industry Webinar, the SDT indicated CAPs in R9 and the additional evaluation under R10 are not intended to be applicable to the
sensitivity portion of the analysis. However, there is no language currently in the standard for this. An auditor, reading the existing language and TPL001-5.1 precedence, could possibly expect additional analysis, which was not intended.
Furthermore, the language regarding applicable regulatory authorities or governing bodies review of CAPs seems like it was originally from the TPL001-5.1 language regarding the use of load shedding for certain P1, P2, and P3 events. As it is currently written, TPL-008 is not consistent with the risk
based approach utilized by TPL-001-5.1 as the TPL-008-1 review by applicable regulatory authorities or governing bodies would be universally required
for all CAPs, not just those that use load shedding as the solution for performance deficiencies (a more limited case under TPL-001-5.1). It is
recommended this language/approach be modified to be consistent with TPL-001-5.1. CAPs themselves do not require such a level of regulatory
review, but if an entity chooses to use load shedding as a solution under R9, then that choice would warrant the additional level of regulatory review.
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Response
Thomas Foltz - AEP - 5
Answer

No

Document Name
Comment
Please see our response to Question #4 regarding load shed considerations.
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0

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0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1 - WECC
Answer

No

Document Name
Comment
R9: No CAPs are overkill for extreme weather events and will add an undue burden on the ratepayers for capital projects. Development of operating
procedures up to and including non-consequential load loss and curtailment of firm transfers should be sufficient for mitigating extreme weather events.
R10: Acceptable
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Response
Lauren Giordano - Lauren Giordano On Behalf of: Dennis Sismaet, Northern California Power Agency, 4, 6, 3, 5; Marty Hostler, Northern
California Power Agency, 4, 6, 3, 5; Michael Whitney, Northern California Power Agency, 4, 6, 3, 5; - Lauren Giordano
Answer

No

Document Name
Comment
NO, These assessment should be performed by the Regional Entities. There appears to be too much room for coordination issues having one
Transmission Planner (TP) or Planning Coordinator (PC) having to rely on other TPs or PCs to meet their requirement deadlines.

Likes

0

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Response
Michael Whitney - Northern California Power Agency - 3, Group Name NCPA
Answer

No

Document Name
Comment
NO, These assessment should be performed by the Regional Entities. There appears to be too much room for coordination issues having one
Transmission Planner (TP) or Planning Coordinator (PC) having to rely on other TPs or PCs to meet their requirement deadlines.
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0

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0

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Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

No

Document Name
Comment
Black Hills Corporation agrees with EEI’s comments on Requirement R9. Modifying the language to match what is in TPL-001-5.1 would better suit this
new standard.
EEI suggests the following modifications to Requirement R9 to better clarify entity obligations under a TPL-008 CAP:
1.
The language in TPL-001 relative to Corrective Action Plans is clearer and we suggest closer alignment to that language (see the suggested
language below).
2.
While PCs and TPs have obligations to notify regulatory authorities and other governing bodies responsible for retail electric service where load
shedding is incorporated into planning contingencies, this should not be included in a NERC Reliability Standard.
3.

Add language similar to that used in Requirement 2, subpart 2.7.3 for situations where TPs and PCs are unable to meeting CAP timeframes.

Proposed Changes to Requirement R9
R9. For Extreme Weather Assessments, which fail to meet the performance requirements for Table 1 P0 or P1 Contingencies, the assessment shall
include Corrective Action Plan(s) (CAPs) addressing how the performance requirements will be met. Revisions to the Corrective Action Plan(s) are
allowed in subsequent Planning Assessments, but the planned System shall continue to meet the performance requirements in Table 1 P0 and P1.

9.1 If situations arise that are beyond the control of the Transmission Planner or Planning Coordinator that prevent the implementation of a Corrective
Action Plan in the required timeframe, then the Transmission Planner or Planning Coordinator is permitted to utilize Non-Consequential Load Loss and
curtailment of Firm Transmission Service to correct the situation that would normally not be permitted in Table 1, provided that the Transmission
Planner or Planning Coordinator documents that they are taking actions to resolve the situation. The Transmission Planner or Planning Coordinator
shall document the situation causing the problem, alternatives evaluated, and the use of Non-Consequential Load Loss or curtailment of Firm
Transmission Service.
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Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

No

Document Name
Comment
How are the criteria for steady-state voltage limits and post-contingency voltage deviations under TPL-008, R5 different from the criteria established for
TPL-001-5.1?
Refer to question 7 comments regarding the requirement to develop Corrective Action Plans for P1 events where system steady state voltages are
outside limits and applicable facility ratings are exceeded.
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Response
Robert Follini - Avista - Avista Corporation - 3
Answer

No

Document Name
Comment
The function of NERC is to ensure bulk electric system delivery of power, not ensure communication with regulatory authorities or governing bodies
external to NERC.
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0

Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

No

Document Name
Comment
FirstEnergy request clarification of who is the intended audience of the Drafting Team for “applicable regulatory authorities or governing bodies
responsible for retail electric service issues” and request clarification and/or focus on NERC Registered Entity assigned in the standard who have
responsibility for R9’s sharing of CAPs.
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Ben Hammer - Western Area Power Administration - 1
Answer

No

Document Name
Comment
WAPA understands that the draft TPL-008-1 Requirement R9 attempts to strike a compromise between obligations to notify and solicit feedback (“low
bar”) from applicable regulatory authorities or governing bodies responsible for retail electric service, versus the precedent obligations (“high bar”)
established by TPL-001-5.1 Attachment 1 where the “Transmission Planner or Planning Coordinator must ensure that the applicable regulatory
authorities or governing bodies responsible for retail electric service issues do not object to the use of Non- Consequential Load Loss under footnote
12.” WAPA agrees with the compromise that the Project 2023-07 SDT has drafted, but recommends a slight simplification to Requirement R9:
R9. Each responsible entity, as identified in Requirement R1, shall develop a Corrective Action Plan(s) (CAPs) when the benchmark planning case
study results indicate the System is unable to meet performance requirements for Table 1 P0 or P1 Contingencies. The responsible entities shall make
their CAP(s), including alternative(s) considered where Load shed is an allowed element of a CAP, available to applicable regulatory authorities or
governing bodies responsible for retail electric service issues. Revisions to the CAP(s) are allowed in subsequent Extreme Temperature Assessments,
but the planned System shall continue to meet the performance requirements.
As background, WAPA as a federal agency is not subject to state regulatory authorities that are responsible for retail electric service. As a result,
WAPA would does not have an "applicable regulatory authority or governing body" for retail electric service issues.
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Isidoro Behar - Long Island Power Authority - 1
Answer
Document Name

No

Comment
Regarding R9:
The use of the term “Load shed” should be replaced with “Non-Consequential Load Loss”, to be consistent with Table 1: Contingencies and
Performance Criteria.
Regarding R9:
In terms of developing a CAP for the “benchmark planning case study results”, it is not clear if the development of a CAP is required for the sensitivity
analysis. Consistency of language with TPL-001-5.1 R2.7 should be considered.
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0

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0

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Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer

No

Document Name
Comment
Consumers Energy agrees with the ocmment by CHPD:
It is unclear if CAPs are required for sensitivity deficiencies. TPL-001-5.1 addresses such things in R2.7.2, however TPL-008-1 does not. In addition, it
is unclear if the sensitivity needs to be run on each R2/R4 case, or only one case. Again, TPL-001-5.1 uses clearer language in R2.1.3.
During the 04/12/2024 Industry Webinar, the SDT indicated CAPs in R9 and the additional evaluation under R10 are not intended to be applicable to the
sensitivity portion of the analysis. However, there is no language currently in the standard for this. An auditor, reading the existing language and TPL001-5.1 precedence, could possibly expect additional analysis, which was not intended.
Furthermore, the language regarding applicable regulatory authorities or governing bodies review of CAPs seems like it was originally from the TPL001-5.1 language regarding the use of load shedding for certain P1, P2, and P3 events. As it is currently written, TPL-008 is not consistent with the risk
based approach utilized by TPL-001-5.1 as the TPL-008-1 review by applicable regulatory authorities or governing bodies would be universally required
for all CAPs, not just those that use load shedding as the solution for performance deficiencies (a more limited case under TPL-001-5.1). It is
recommended this language/approach be modified to be consistent with TPL-001-5.1. CAPs themselves do not require such a level of regulatory
review, but if an entity chooses to use load shedding as a solution under R9, then that choice would warrant the additional level of regulatory review.
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Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
Please refer to Question 1 comments.
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Leslie Hamby - Southern Indiana Gas and Electric Co. - 3,5,6 - RF
Answer

No

Document Name
Comment
R9: Similarly to other commenters, Southern Indiana Gas & Electric Company d/b/a CenterPoint Energy Indiana South (SIGE) is requesting clarification
as to whether CAPS are required for sensitivity deficiencies and if the sensitivity needs to be run on each R2/R4 case or only one case.
Additionally, SIGE is recommending removing “The responsible entities shall share their CAPs with, and solicit feedback from, applicable regulatory
authorities or governing bodies responsible for retail electric service issues” and “but the planned System shall continue to meet the performance
requirements.” Changes are illustrated below:
R9. Each responsible entity, as identified in Requirement R1, shall develop a Corrective Action Plan(s) (CAPs) when the benchmark planning case
study results indicate the System is unable to meet performance requirements for Table 1 P0 or P1 Contingencies.
In addition, where Load shed is allowed as an element of a CAP for the Table 1 P1 Contingency, the responsible entity shall document the alternative(s)
considered, as mentioned in Requirement R10, and notify the applicable regulatory authorities or governing bodies responsible for retail electric service
issues. Revisions to the CAP(s) are allowed in subsequent Extreme Temperature Assessments.
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Apollonia Gonzales - PNM Resources - 1,3 - WECC,Texas RE
Answer

No

Document Name
Comment
PNMR requests the SDT provide more justification for including the regulatory authorities or governing bodies responsible for retail electric service
issues.

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0

Response
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
Since the Standard covers the Planning Horizon, BPA recommends the P0 base case include all transmission lines in service. If P0 case already
includes multiple transmission outages, it is very likely Corrective Action Plans will be cost-prohibitive and cause undue burden on transmission
providers. P0 case transmission outages could be treated as sensitivities in R8 with no CAP requirement. BPA highly recommends that P5 not be
included as part of the required studies because extreme weather conditions expose outdoor EHV elements and do not affect protective relaying.

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Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

No

Document Name
Comment
Proposed TPL-008 has sensitivities, unclear if CAPs are needed. Requirement R9 does not capture how TPL-001 approach.
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Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Document Name
Comment

No

R9 language is similar to a footnote in TPL-001 that requires a process (now captured in the ERO Enterprise Periodic Data Schedule.) As such clarity
and consistency with the language should be sought out. Additionally, does the language meet the requirements within TPL-001? "Sharing" of the
CAPs is not defined and more clarity on timing, method, and expectations needs to be provided. R10--It is not clear what the responsible entity will do
with the "possible actions". If anything they should be provided to the operators (BA/RC/TOPs) to prepare Plans/Processes as needed. In one respect
if the Assessment is only done once per 5 calendar years, how valuable are the corrective actions for the assessment without updates as the system
changes are/are not implemented?
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0

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0

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Lenise Kimes - City and County of San Francisco - 1,5 - WECC
Answer

No

Document Name
Comment
• R9 – As written, this requirement states that the responsible entity “shall develop” CAPs for P0 and P1, but does not state if these CAPs must be
“implemented” prior to the operating horizon. TPL-001-5.1, R2.7.3 allows use of NCLL under circumstances where CAPs cannot be implemented in the
required timeframe (i.e., prior to the operating horizon). TPL-008, Table 1 allows for use of NCLL for P1, P2, P4, P5 and P7 events, but not for P0.
o Are entities required to implement CAPs prior to the operating horizon, including construction of capital projects?
o If an entity is unable to complete a capital project or implement an Operating Plan prior to the operating horizon, would NCLL be allowed for P0?
o We recommend that this situation be addressed in a similar fashion to TPL-001.

• R9 uses the term “Load shed”, but Table 1 in TPL-008 and TPL-001 both use the term NCLL.
o We recommend that R9 be revised to use the term “NCLL” instead of “Load shed” for consistency and clarity.

• R10 – As discussed in the comments for R7, we strongly recommend that P5 be removed from R7, R10, and Table 1 due to the low probability of
such events during Extreme Temperature events.

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0

Israel Perez - Israel Perez On Behalf of: Mathew Weber, Salt River Project, 3, 1, 6, 5; Matthew Jaramilla, Salt River Project, 3, 1, 6, 5; Thomas
Johnson, Salt River Project, 3, 1, 6, 5; Timothy Singh, Salt River Project, 3, 1, 6, 5; - Israel Perez
Answer

No

Document Name
Comment
SRP feels that this is far too much in a single requirement. Develop a CAP and communicate the CAP should be broken out. Additionally, what is meant
by "solicit feedback". Finally, the load shed stipulation should be criteria, not part of the requirement.
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0

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Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

No

Document Name
Comment
Minnesota Power supports MRO’s NERC Standards Review Forum’s (NSRF) comments.
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0

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0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

No

Document Name
Comment
Oncor strongly disagrees with the following statement in R9: “The responsible entities shall share their CAPs with, and solicit feedback from, applicable
regulatory authorities or governing bodies responsible for retail electric service issues.” We propose that “applicable regulatory authorities or governing
bodies” be defined and limited. For example, a TP should only need to provide their PC with CAP information.
In addition, we disagree with the following phrase “…and notify the applicable regulatory authorities or governing bodies responsible for retail electric
service issues” as it relates to Load Shed. The intended regulatory audience needs to be clearly defined.
Oncor disagrees with R10 as well. The requirement does not give TPs the ability to create CAPs for the listed contingencies.

Likes

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0

Response
Joshua London - Eversource Energy - 1, Group Name Eversource
Answer

No

Document Name
Comment
R9: Eversource suggests language be added similar to TPL-001 stating that CAPs are not required for sensitivity analysis.

Eversource also questions the statement “solicit feedback from applicable regulatory authorities or governing bodies responsible for retail electric
service issues.” If an applicable governing body disagrees with the result or says no to the CAP, is it no longer required to perform it?
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Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
Dominion Energy supports EEI comments. In addition, Developing CAPs for extreme events that are selected from a library of “approved cases” will not
necessarily protect the BES from future extreme events. Providing the results of these analyses to other regulatory bodies is of concern as to how that
information will be used and understood.
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0

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0

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Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer
Document Name
Comment

No

MPC supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
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Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

No

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and Midwest Reliability Organization's NERC
Standards Review Forum (MRO NSRF) on question 5
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0

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0

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Kristine Martz - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment
EEI suggests the following modifications to Requirement R9 to better clarify entity obligations under a TPL-008 CAP:
1.
The language in TPL-001 relative to Corrective Action Plans is clearer and we suggest closer alignment to that language (see the suggested
language below).
2.
While PCs and TPs may have obligations to notify regulatory authorities and other governing bodies responsible for retail electric service where
load shedding is incorporated into planning contingencies, this should not be included in a NERC Reliability Standard.
3.
Add language similar to that used in TPL-001 Requirement 2, subpart 2.7.3 for situations where TPs and PCs are unable to meet CAP
timeframes.
Proposed Changes to Requirement R9
R9. For Extreme Weather Assessments, which fail to meet the performance requirements for Table 1 P0 or P1 Contingencies, the assessment shall
include Corrective Action Plan(s) (CAPs) addressing how the performance requirements will be met. Revisions to the Corrective Action Plan(s) are
allowed in subsequent Planning Assessments, but the planned System shall continue to meet the performance requirements in Table 1 P0 and P1.

9.1 If situations arise that are beyond the control of the Transmission Planner or Planning Coordinator that prevent the implementation of a Corrective
Action Plan in the required timeframe, then the Transmission Planner or Planning Coordinator is permitted to utilize Non-Consequential Load Loss and
curtailment of Firm Transmission Service to correct the situation that would normally not be permitted in Table 1, provided that the Transmission
Planner or Planning Coordinator documents that they are taking actions to resolve the situation. The Transmission Planner or Planning Coordinator
shall document the situation causing the problem, alternatives evaluated, and the use of Non-Consequential Load Loss or curtailment of Firm
Transmission Service.
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0

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0

Response
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer

No

Document Name
Comment
LG&E and KU agrees with EEI's comments.
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0

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0

Response
Richard Vendetti - NextEra Energy - 5
Answer

No

Document Name
Comment
R9 – Disclosure of acceptable thresholds mentioned in question #4 comments should also be provided to relevant regulatory authorities.

R10 – As noted, thermal overloads or cascades mitigated by load drops should not exceed an established threshold documented by PC and TP.
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Response
Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza

Answer

No

Document Name
Comment
•

•
•

R9 indicates that CAPs should be developed “…when the benchmark planning case study results indicate the System is unable to meet
performance requirements…” but it is not clear whether the sensitivity analysis is included in “benchmark planning case study results”. For
comparison, TPL-001-5.1 states that “Corrective Action Plan(s) do not need to be developed solely to meet the performance requirements for a
single sensitivity case….” Should something similar be stated in TPL-008, or is the intent that any case or sensitivity performance violation
should trigger a CAP?
Additionally, R9 requires that “The responsible entities shall share their CAPs with, and solicit feedback from, applicable regulatory authorities
or governing bodies responsible for retail electric service issues.” This is unique to this standard and should be removed.
R9, R10: “Responsible entity” should be defined in the Applicability section or should replaced with “Each Planning Coordinator, in conjunction
with its Transmission Planner(s)...” ). Suggest to replace 4.1 to “Responsible Entity” instead of “Functional Entity”.

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0

Response
Michele Tondalo - United Illuminating Co. - 1
Answer

No

Document Name
Comment
R9 requires soliciting feedback from external, non-registered entities (“…applicable regulatory authorities…”) but it is not clear what to do with this
feedback and if there is the potential for an auditor and Registered Entity disagree with how feedback is used. I recommend considering updates to this
wording to include similar steps as CIP-014 R2.3 which could allow for modification or documentation of technical rationale for not making modification,
if requested by the applicable regulatory authorities.
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0

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0

Response
Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

No

Document Name
Comment
R9 requires soliciting feedback from external, non-registered entities (“…applicable regulatory authorities…”) but it is not clear what to do with this
feedback and if there is the potential for an auditor and Registered Entity disagree with how feedback is used. I recommend considering updates to this
wording to include similar steps as CIP-014 R2.3 which could allow for modification or documentation of technical rationale for not making modification,
if requested by the applicable regulatory authorities.

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Glen Farmer - Avista - Avista Corporation - 5
Answer

No

Document Name
Comment
EEI suggests the following modifications to Requirement R9 to better clarify entity obligations under a TPL-008 CAP:

1. The language in TPL-001 relative to Corrective Action Plans is clearer and we suggest closer alignment to that language (see the suggested
language below).

2. While PCs and TPs may have obligations to notify regulatory authorities and other governing bodies responsible for retail electric service where load
shedding is incorporated into planning contingencies, this should not be included in a NERC Reliability Standard.
3. Add language similar to that used in TPL-001 Requirement 2, subpart 2.7.3 for situations where TPs and PCs are unable to meet CAP timeframes.
Proposed Changes to Requirement R9

R9. For Extreme Weather Assessments, which fail to meet the performance requirements for Table 1 P0 or P1 Contingencies, the assessment shall
include Corrective Action Plan(s) (CAPs) addressing how the performance requirements will be met. Revisions to the Corrective Action Plan(s) are
allowed in subsequent Planning Assessments, but the planned System shall continue to meet the performance requirements in Table 1 P0 and P1.

9.1 If situations arise that are beyond the control of the Transmission Planner or Planning Coordinator that prevent the implementation of a Corrective
Action Plan in the required timeframe, then the Transmission Planner or Planning Coordinator is permitted to utilize Non-Consequential Load Loss and
curtailment of Firm Transmission Service to correct the situation that would normally not be permitted in Table 1, provided that the Transmission
Planner or Planning Coordinator documents that they are taking actions to resolve the situation. The Transmission Planner or Planning Coordinator
shall document the situation causing the problem, alternatives evaluated, and the use of Non-Consequential Load Loss or curtailment of Firm
Transmission Service.

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Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
•
•
•
•
•

The purpose and required response actions related to the sharing of CAPs and solicitation of feedback is not clear.
The role of the TO and/or GO in implementing or otherwise responding to CAPs that may require additions or modifications to their
systems/facilities is not captured in these requirements.
There appears to be a significant amount of outside review required but no clear actions the responsible entity is required to take, particularly if
there is a dispute.
The purpose and reliability benefit of R10 is ambiguous. It is understood that P2, P4, P5, & P7 events tend to be lower probability but
documenting possible mitigations every 5 years for these low-probability events in an extreme weather condition appears more administrative
than reliability-based as the requirement is currently written.
The exclusion of the P3 & P6 events from these requirements is appropriate. The SDT should consider if specific P2, P4, P5, & P7 events
should likewise be excluded so the standard only addresses those events that must be evaluated and mitigated.

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Response
Brittany Millard - Lincoln Electric System - 5
Answer

No

Document Name
Comment
LES supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
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Katrina Lyons - Georgia System Operations Corporation - 4
Answer

No

Document Name
Comment
GSOC supports Georgia Transmission Corporation's comments:
•
•

The purpose and required response actions related to the sharing of CAPs and solicitation of feedback is not clear.
The role of the TO and/or GO in implementing or otherwise responding to CAPs that may require additions or modifications to their
systems/facilities is not captured in these requirements.

•
•
•

There appears to be a significant amount of outside review required but no clear actions the responsible entity is required to take, particularly if
there is a dispute.
The purpose and reliability benefit of R10 is ambiguous. It is understood that P2, P4, P5, & P7 events tend to be lower probability but
documenting possible mitigations every 5 years for these low-probability events in an extreme weather condition appears more administrative
than reliability-based as the requirement is currently written.
The exclusion of the P3 & P6 events from these requirements is appropriate. The SDT should consider if specific P2, P4, P5, & P7 events
should likewise be excluded so the standard only addresses those events that must be evaluated and mitigated.

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Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

No

Document Name
Comment
We support EEI's comments.
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Response
Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer

No

Document Name
Comment
AECI supports comment provided by Georgia Transmission Corporation
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Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name

No

Comment
Duke Energy agrees with and endorses EEI comments.
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Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer

No

Document Name
Comment
In R9, a CAP must to be provided to a regulatory authority for a Long-term planning assessment. ISO agrees a CAP should be documented with possible actions,
however this is a planning assessment. Providing a CAP to regulatory authorities may only cause more confusion and work for the industry. Additionally, a CAP
developed through the planning process may require implementation of tariff processes before the CAP may proceed. Providing a CAP to a regulator would be
premature if the tariff required processes have not been completed.
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Response
Junji Yamaguchi - Hydro-Quebec (HQ) - 5
Answer

No

Document Name
Comment
R9 indicates that CAPs should be developed “…when the benchmark planning case study results indicate the System is unable to meet performance
requirements…” but it is not clear whether the sensitivity analysis is included in “benchmark planning case study results”. For comparison, TPL-001-5.1
states that “Corrective Action Plan(s) do not need to be developed solely to meet the performance requirements for a single sensitivity case….” Should
something similar be stated in TPL-008, or is the intent that any case or sensitivity performance violation should trigger a CAP?

Additionally, R9 requires that “The responsible entities shall share their CAPs with, and solicit feedback from, applicable regulatory authorities or
governing bodies responsible for retail electric service issues.” This is unique to this standard and should be removed.

R9, R10: “Responsible entity” should be defined in the Applicability section or should replaced with “Each Planning Coordinator, in conjunction with its
Transmission Planner(s)...” ). Suggest to replace 4.1 to “Responsible Entity” instead of “Functional Entity”.

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David Jendras Sr - Ameren - Ameren Services - 3
Answer

No

Document Name
Comment
R9: Ameren does not support reporting benchmark planning case study results to applicable entities. TPL-001 does not have a similar requirement for
reporting retail electric service issues.
R10: Ameren suggests removing the phrase "reduce the likelihood or" from the requirement.
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Colby Galloway - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment
Southern Company disagrees with the statement that it should solicit CAP feedback from applicable regulatory bodies or governing bodies. The action
of regulatory feedback/approval does not comport with a risk-based action and only serves as an administrative burden that could further delay reliability
to the BES. This is a compliance risk without a Reliability benefit. The NERC standard should solely focus on identifying the problem and identifying
the projects, not mandating a regulatory strategy for the implementation of projects. This is beyond the purview of a reliability standard. It is Southern
Company’s recommendation that requirements to share CAPs and solicit feedback from regulatory bodies in R9 should be removed from the
standard. It has been a well document practice to create/implment CAPs, giving greater assurity of corrective measures that impact the BES and these
are auditable for Reginal Entity assurance. What is now becoming more administrative is the requirement to report and "wait" for approval, which could
unduly delay a Registered Entity from implementing and thus cause undue harm to the BES.
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Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer

No

Document Name
Comment
It is not clear why R9 is requiring soliciting CAP feedback from regulatory authorities for retail electric service issues.
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Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

No

Document Name
Comment
R9 – As written, this requirement states that the responsible entity “shall develop” CAPs for P0 and P1, but does not state if these CAPs must be
“implemented” prior to the operating horizon. TPL-001-5.1, R2.7.3 allows use of NCLL under circumstances where CAPs cannot be implemented in the
required timeframe (i.e., prior to the operating horizon).
If an entity is unable to complete a capital project or implement an Operating Plan prior to the operating horizon, we recommend that NCLL be allowed
for P0 under the extreme weather condition

R9 uses the term “Load shed”, but Table 1 in TPL-008 and TPL-001 both use the term NCLL.
We recommend that R9 be revised to use the term “NCLL” instead of “Load shed” for consistency and clarity.

R10 – As discussed in the comments for R7, we strongly recommend that P5 be removed from R7, R10, and Table 1 due to the low probability of such
events during Extreme Temperature events.
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Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer
Document Name
Comment

No

Should GOs have applicability in the standard if a concern is identified that too much generation is unavailable due to the parameters for the hot and
cold events?

Proposed wording change for part of R9:

“Revisions to the CAP(s) are allowed in subsequent Extreme Temperature Assessments, so long as but the planned System shall continues to meet the
performance requirements.”
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Robert Jones - Seattle City Light - 1,3,4,6
Answer

No

Document Name
Comment
The language is not very specific as compared to TPL-001. Does it pertain to Steady state, sensitivities, and/or transient stability studies? Depending on
how the criteria or methodology is defined by each entity, an entity may exclude sensitivities from a CAP if there is a violation. The point is the language
in this standard is vague.
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Response
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

No

Document Name
Comment
NIPSCO supports the comments provided by AEP, FE, WAPA, CHPD, CMS Energy, and WPP.
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Selene Willis - Edison International - Southern California Edison Company - 5
Answer

No

Document Name
Comment
“See comments submitted by the Edison Electric Institute”
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Daniel Gacek - Exelon - 1
Answer

No

Document Name
Comment
R10 - Perhaps more clarity on how that might differ from stability studies on P0 and P1 contingencies can be added to this requirement.
Additionally, Exelon supports the comments provided by the EEI for this question.
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Response
Amy Wilke - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
ATC generally supports the MRO NSRF comments, and is supplementing them as described below.
R9, R10: Please verify that the sensitivities do not require CAPs or documentation of possible mitigating actions and are for information only.
R10: It might be helpful to document why R10’s requirement to come up with potential CAPs for non-P0 and P1s is needed. What actually happens
with the possible actions required under R10? Is this similar to how extreme events are currently treated?
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer

No

Document Name
Comment
R9 indicates that CAPs should be developed “…when the benchmark planning case study results indicate the System is unable to meet performance
requirements…” but it is not clear whether the sensitivity analysis is included in “benchmark planning case study results”. For comparison, TPL-001-5.1
states that “Corrective Action Plan(s) do not need to be developed solely to meet the performance requirements for a single sensitivity case….” Should
something similar be stated in TPL-008, or is the intent that any case or sensitivity performance violation should trigger a CAP?

Additionally, R9 requires that “The responsible entities shall share their CAPs with, and solicit feedback from, applicable regulatory authorities or
governing bodies responsible for retail electric service issues.” This is unique to this standard and should be removed.

R9, R10: “Responsible entity” should be defined in the Applicability section or should replace with “Each Planning Coordinator, in conjunction with its
Transmission Planner(s)...”). Suggest replacing
4.1 to “Responsible Entity” instead of “Functional Entity”.
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0

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Response
Kinte Whitehead - Exelon - 3
Answer

No

Document Name
Comment
R10 - Perhaps more clarity on how that might differ from stability studies on P0 and P1 contingencies can be added to this requirement.
Additionally, Exelon supports the comments provided by the EEI for this question.
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Wayne Guttormson - SaskPower - 1
Answer

No

Document Name
Comment
Support the MRO NSRF and EEI comments.
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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO,WECC, Group Name SPP RTO
Answer

No

Document Name
Comment
SPP has a concern about language in Requirement R9 as it talks about “governing bodies”. It is unclear who identifies and aligns with that role and
responsibility.
SPP recommends that the drafting team provide clarity on which entities qualify for the role and responsibility.

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Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

No

Document Name
Comment
NV Energy suggests the following modifications to Requirement R9 to better clarify entity obligations under a TPL-008 CAP:

{C}1. {C}The language in TPL-001 relative to Corrective Action Plans is clearer and we suggest closer alignment to that language (see the suggested
language below).
{C}2. {C}While PCs and TPs have obligations to notify regulatory authorities and other governing bodies responsible for retail electric service where
load shedding is incorporated into planning contingencies, this should not be included in a NERC Reliability Standard.
{C}3.

{C}Add language similar to that used in Requirement 2, subpart 2.7.3 for situations where TPs and PCs are unable to meeting CAP timeframes.

Proposed Changes to Requirement R9

R9. For Extreme Weather Assessments, which fail to meet the performance requirements for Table 1 P0 or P1 Contingencies, the assessment shall
include Corrective Action Plan(s) (CAPs) addressing how the performance requirements will be met. Revisions to the Corrective Action Plan(s) are
allowed in subsequent Planning Assessments, but the planned System shall continue to meet the performance requirements in Table 1 P0 and P1.

9.1 If situations arise that are beyond the control of the Transmission Planner or Planning Coordinator that prevent the implementation of a Corrective
Action Plan in the required timeframe, then the Transmission Planner or Planning Coordinator is permitted to utilize Non-Consequential Load Loss and
curtailment of Firm Transmission Service to correct the situation that would normally not be permitted in Table 1, provided that the Transmission
Planner or Planning Coordinator documents that they are taking actions to resolve the situation. The Transmission Planner or Planning Coordinator
shall document the situation causing the problem, alternatives evaluated, and the use of Non-Consequential Load Loss or curtailment of Firm
Transmission Service.
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Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT recommends that the drafting team resolve an apparent inconsistency regarding the P0 analysis. Specifically, the Technical Rationale appears
to suggest that Load shedding is permitted to establish a solvable P0 system condition. However, Requirement R9 and Table 1 do not seem to allow
Load shedding for solvable P0 system condition. ERCOT recommends that the drafting team address this by revising Requirement R9 to explicitly
indicate that Load shed is allowed to establish a solvable P0 system condition. This is necessary to ensure that the study can assume sufficient
resources are available in a P0 state. This, in turn, is necessary to prevent the standard from straying into the realm of resource adequacy. As noted in
the Technical Rationale, resource adequacy is not in scope for this project under paragraph 94 of FERC Order No. 896.

It is also unclear why Requirement R9 requires entities to submit CAPs to regulatory authorities or governing bodies responsible for “retail electric
service issues.” These types of regulatory authorities are not subject to NERC requirements, but do generally have authority over generation
planning. Consequently, the mandate to submit CAPs to these regulatory authorities or governing bodies appears to address a resource adequacy

issue. However, as noted in the Technical Rationale, paragraph 94 of FERC Order No. 896 provides that resource adequacy is not in scope for this
project. ERCOT therefore recommends that the requirement to submit CAPs to regulatory authorities or governing bodies be removed from the
standard.
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Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

No

Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments.
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Response
Catrina Martin - Archer Energy Solutions, LLC - 5
Answer

No

Document Name
Comment
R9 – As written, this requirement states that the responsible entity “shall develop” CAPs for P0 and P1, but does not state if these CAPs must be
“implemented” prior to the operating horizon. TPL-001-5.1, R2.7.3 allows use of NCLL under circumstances where CAPs cannot be implemented in the
required timeframe (i.e., prior to the operating horizon). TPL-008, Table 1 allows for use of NCLL for P1, P2, P4, P5 and P7 events, but not for P0.
o Are entities required to implement CAPs prior to the operating horizon, including construction of capital projects?
o If an entity is unable to complete a capital project or implement an Operating Plan prior to the operating horizon, would NCLL be allowed for P0?
o We recommend that this situation be addressed in a similar fashion to TPL-001.

R9 uses the term “Load shed”, but Table 1 in TPL-008 and TPL-001 both use the term NCLL.
o We recommend that R9 be revised to use the term “NCLL” instead of “Load shed” for consistency and clarity.

R10 – As discussed in the comments for R7, we strongly recommend that P5 be removed from R7, R10, and Table 1 due to the low probability of such
events during Extreme Temperature events.

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Response
Michael Goggin - Grid Strategies LLC - 5
Answer

No

Document Name
Comment
a. Requirement R9 should be modified to specify that the expected impact of extreme heat and cold should be accounted for when designing and
measuring the impact of the solutions proposed in a Corrective Action Plan (CAP). Many potential solutions in a CAP can have greater or lesser impact
under extreme heat or cold conditions. For example, a CAP that relies on adding gas generation can be less effective under extreme heat due to output
reductions due to ambient temperature derates, and under extreme cold due to correlated gas generator outages. Gas generator outages due to
equipment failures and fuel supply interruptions have accounted for the majority of outages during recent cold snap events.{C}[1] As noted above in
response to question 4, FERC’s directive in paragraph 89 of Order 896 states that “it is necessary that responsible entities evaluate the risk of
correlated or concurrent outages and derates of all types of generation resources and transmission facilities as a result of extreme heat and cold
events.” On the other hand, CAPs that include demand response and energy efficiency programs related to building HVAC systems can offer
contributions that are larger than expected during extreme heat or cold because load associated with cooling or heating is higher during such events.
During extreme cold events, expanded transmission ties with neighboring grid operators can also exceed the benefits they offer under normal conditions
because transmission line thermal limits are higher during extreme cold and wind chill conditions. Transmission ties also tend to offer large benefits
during extreme heat and cold, as severe weather events tend to be at their most extreme in geographically confined areas, ensuring at least some
nearby grid operators are not experiencing shortfalls in generation.[2] The benefits of interregional transmission are even greater at higher renewable
penetrations.[3] The value of transmission ties during extreme heat and cold events should be accounted for when assessing baseline performance
during benchmark events as well as quantifying the value of expanding these ties as part of a CAP.
The higher transfer capacity of advanced conductors under extreme heat and cold conditions should also be accounted for, as carbon and composite
core conductors sag roughly half as much as comparable ACSR conductors. Finally, Grid-Enhancing Technologies like dynamic line ratings, topology
optimization, and power flow control devices offer significant benefits when the grid may be congested due to extreme temperatures. Dynamic line
ratings are particularly valuable for enabling operators to safely use transmission lines’ higher thermal limits during extreme cold and wind chill
conditions.
Accounting for how a CAP will fare under the extreme heat or cold conditions it is designed to solve is essential for ensuring reliability. Without
accounting for the reduced effectiveness of some CAP elements under extreme heat or cold, planners will be blind to potential reliability risks. In other
cases, failing to account for the effectiveness of specific CAP measures under extreme heat or cold will result in a suboptimal selection of solutions.
Extreme heat and cold must not only be accounted for in identifying reliability risks, but also designing solutions to those risks.
b. The draft of R9 also includes two potential loopholes that a responsible entity could use to avoid implementing a CAP that is needed to address
reliability concerns. The Technical Rationale document explains that “under an extreme heat or extreme cold temperature condition, there may
instances where the benchmark planning cases and/or sensitivity cases may not have sufficient available generation to supply the load. In these
scenarios, it may be acceptable for the responsible entity to either curtail load, or model most likely future resources in the interconnection queue, to
achieve a solution for the benchmark planning case.” That document also notes that “the SDT has determined that load curtailment may be considered

for a P1 Contingency as a CAP where load shed is allowed to prevent system-wide failures and ensuring the continued operation of essential services
under a critical P1 Contingency in the extreme heat and cold events.”
First, allowing load curtailment for a P1 contingency under TPL-008 is a major departure from the requirements of TPL-001, which do not allow load
shedding for a P1 contingency.{C}[4] Allowing responsible entities plans’ to include load shed when they experience a single P1 contingency under
extreme heat or cold conditions is contrary to FERC’s intent in Order 896 that NERC enact a standard that will ensure reliable operations under extreme
heat and cold conditions.
Second, for the option to “model most likely future resources in the interconnection queue, to achieve a solution for the benchmark planning case” to be
an effective solution to reliability concerns, it must be accompanied by requirements for those resources to have signed procurement contracts or at
least be included in a load-serving entity’s plan, and/or a requirement to later confirm that those resources have actually been built. Without such a
requirement, a responsible entity could comply with TPL-008 by simply speculating that some share of the large backlog of proposed resources
currently in the interconnection queue in nearly all regions will be built.
More generally, a major concern with the draft standard is that there is no compliance mechanism to ensure CAPs are implemented. As drafted, R9 and
the other requirements only require that “The responsible entities shall share their CAPs with, and solicit feedback from, applicable regulatory authorities
or governing bodies responsible for retail electric service issues.... Revisions to the CAP(s) are allowed in subsequent Extreme Temperature
Assessments, but the planned System shall continue to meet the performance requirements.” If implementing some CAP solutions requires action by an
entity other than the transmission planner or planning coordinator responsible entities, the draft standard should be revised to include such a
requirement on those entities. Other draft NERC standards include requirements to implement CAPs, and similar language could be adopted for TPL008. For example, requirement R9 of the PRC-028 draft requires a generator or transmission owner to “develop, maintain, and implement a Corrective
Action Plan to provide the required capability,”{C}[5] and requirement R6 of the PRC-030 draft requires “Each applicable Generator Owner shall, for
each of its CAPs developed pursuant to Requirement R5:
6.1. Implement the CAP;
6.2. Update the CAP if actions or timetables change; and
6.3. Notify each applicable Reliability Coordinator if CAP actions or timetables change and when the CAP is completed.”[6]{C}

{C}[1]{C} See, e.g., FERC and NERC, Winter Storm Elliott Report: Inquiry into Bulk-Power System Operations During December 2022 (October 2023),
https://www.ferc.gov/media/winter-storm-elliott-report-inquiry-bulk-power-system-operations-during-december-2022, at 17; FERC and NERC, The
February 2021 Cold Weather Outages in Texas and the South Central United States (November 2021), https://www.ferc.gov/media/february-2021-coldweather-outages-texas-and-south-central-united-states-ferc-nerc-and, at 16; FERC and NERC, 2019 FERC and NERC Staff Report: The South Central
United States Cold Weather Bulk Electric System Event of January 17, 2018 (July 2019), https://www.ferc.gov/legal/staff-reports/2019/07-18-19-fercnerc-report.pdf; PJM, Analysis of Operational Events and Market Impacts During the January 2014 Cold Weather Events (May 2014),
https://www.pjm.com/~/media/library/reports-notices/weather-related/20140509-analysis-of-operational-events-and-market-impacts-during-the-jan-2014cold-weather-events.ashx.
{C}[2]{C} https://acore.org/wp-content/uploads/2021/07/GS_Resilient-Transmission_proof.pdf
{C}[3]{C} https://www.nrel.gov/docs/fy22osti/78394.pdf
{C}[4]{C} https://www.nerc.com/pa/Stand/Reliability%20Standards/TPL-001-5.pdf, at 21
{C}[5]{C} https://www.nerc.com/pa/Stand/Project202104ModificationstoPRC0022DL/2021-04_AB_PRC-028-1_Clean_03182024.pdf
{C}[6]{C} https://www.nerc.com/pa/Stand/Project202302PerformanceofIBRsDL/2023-02%20PRC-030-1_032524.pdf
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Response
Adrian Harris - Adrian Harris On Behalf of: Bobbi Welch, Midcontinent ISO, Inc., 2; - Adrian Harris, Group Name RTO/ISO Council Standard
Review Committee Project 2023-07 TPL-008
Answer

Yes

Document Name
Comment
R9. The SRC observes that R9 requires responsible entities to share their CAPs with, and solicit feedback from, applicable regulatory authorities or
governing bodies responsible for retail electric service issues in all cases. This may extend the amount of time needed for CAP approval.

The SRC recommends that the drafting team resolve an apparent inconsistency regarding the P0 analysis. Specifically, the technical rationale appears
to suggest that Load shedding is permitted to establish a solvable P0 system condition. However, Requirement R9 and Table 1 do not seem to allow
load shedding for solvable P0 system condition. The SRC recommends that the drafting team address this by revising Requirement R9 to explicitly
indicate that Load shed is allowed to establish a solvable P0 system condition. This is necessary to ensure that the study can assume sufficient
resources are available in a P0 state. This, in turn, is necessary to prevent the standard from straying into the realm of resource adequacy. As noted in
the Technical Rationale, resource adequacy is not in scope for this project under paragraph 94 of FERC Order No. 896.
It is also unclear why Requirement R9 requires entities to submit CAPs to regulatory authorities or governing bodies responsible for “retail electric
service issues.” These types of regulatory authorities are not subject to NERC requirements, but do generally have authority over generation planning.
Consequently, the mandate to submit CAPs to these regulatory authorities or governing bodies appears to address a resource adequacy issue.
However, as noted in the Technical Rationale, paragraph 94 of FERC Order No. 896 provides that resource adequacy is not in scope for this project.
The SRC therefore recommends that the requirement to submit CAPs to regulatory authorities or governing bodies be removed from the standard.If this
requirement is not removed, the SRC notes that the requirement to solicit feedback from applicable regulatory authorities responsible for retail electric
service issues imposes a higher burden beyond what is required in TPL-001, and requests that the drafting team provide an explanation or justification
regarding the need for this higher burden.

IESO Abstains from Question 5
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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Document Name
Comment

Yes

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0

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0

Response
Mark Flanary - Midwest Reliability Organization - 10
Answer

Yes

Document Name
Comment
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0

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Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

Yes

Document Name
Comment
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Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst Ballot
Body Member and Proxies
Answer

Yes

Document Name
Comment
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Response

0

Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

Yes

Document Name
Comment
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0

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0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Kimberly Turco - Constellation - 6
Answer
Document Name
Comment
Constellation has no comments
Kimberly Turco on behalf of Constellation Segments 5 and 6
Likes

0

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0

Response
Alison MacKellar - Constellation - 5
Answer
Document Name
Comment
Constellation has no comments
Alison Mackellar on behalf of Constellation Segments 5 and 6
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0

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0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment

Texas RE has the following comments:
•
•

Texas RE recommends including a timeframe for which the CAPs need to be developed once the benchmark planning case study results
indicate the System is unable to meet performance requirements.
Requirement R9 is essentially three requirements. It would be easier to read if each Requirement R9 contained subparts or bullets:

R9. Each responsible entity, as identified in Requirement R1, shall develop a Corrective Action Plan(s) (CAPs) when the benchmark planning case
study results indicate the System is unable to meet performance requirements for Table 1 P0 or P1 Contingencies.
9.1 The responsible entities shall share their CAPs with, and solicit feedback from, applicable regulatory authorities or governing bodies responsible for
retail electric service issues.
9.2 In addition, where Load shed is allowed as an element of a CAP for the Table 1 P1 Contingency, the responsible entity shall document the
alternative(s) considered, as mentioned in Requirement R10, and notify the applicable regulatory authorities or governing bodies responsible for retail
electric service issues
9.3 Revisions to the CAP(s) are allowed in subsequent Extreme Temperature Assessments, but the planned System shall continue to meet the
performance requirements.
•

Likes

Texas RE noticed the Performance Criteria states that non-consequential Load loss is allowed for P1 contingencies for Requirement R9, but a
limit for the maximum amount of non-consequential load loss is not specified. This seems to indicate that any level of firm-load shed is allowed
for any of the P1 contingencies. SDT should consider providing additional clarifications on the firm-load shed levels, how to manage model
uncertainties, etc. when developing Corrective Action Plans and the implementation schedule.
0

Dislikes
Response

0

6. Do you agree with the proposed TPL-008-1 Reliability Standard Requirement R11 (Sharing Extreme Temperature Assessment results)? If
you do not agree, please provide your recommendation and, if appropriate, technical or procedural justification.
Adrian Harris - Adrian Harris On Behalf of: Bobbi Welch, Midcontinent ISO, Inc., 2; - Adrian Harris, Group Name RTO/ISO Council Standard
Review Committee Project 2023-07 TPL-008
Answer

No

Document Name
Comment
The SRC supports the “upon request” nature of R11 and sharing Extreme Temperature Assessment results with those having a “reliability need.”
That said, the wording of Requirement R11 is unclear. In light of NERC’s retirement of the functional model, referring to a “NERC-registered entity”
instead of a “functional entity” would be clearer. Alternatively, if Requirement R11 is only intended to require provision of the assessment results to
Transmission Planners and Planning Coordinators, Requirement R11 should be revised to explicitly reference these two types of entities.
R11. Each responsible entity, as identified in Requirement R1, shall provide its Extreme Temperature Assessment results within 90 calendar days of a
request to any NERC-registered entity that has a reliability related need and submits a written request for the information.
Q7. The SRC recommends the following clarifications to Table 1:
•
•
•

in the Facility Voltage Level of Contingency row, change the commas to colons,
in the Facility Voltage Level of Contingency row, clarify what is meant by “reference voltage,” and
in the Stability Performance Criteria row, clarify what is meant by “initialization.”

Additionally, the SRC recommends that the drafting team either include the full set of footnotes from TPL-001-5.1 Table 1 or clarify why TPL-008
contains only a limited subset of the footnotes to Table 1.The SRC also requests that the drafting team confirm that Table 1 will be limited to 200 kV and
above facilities and not include contingencies below 200 kV, as this could miss contingency events below 200 kV that could be limiting to the 200 kV
and up system.
Finally, consistent with the SRC’s comments on the need for Requirement R9 to clarify that Load shed is allowed to establish a solvable P0 system
condition, the SRC recommends that Table 1 be revised to contain the same clarification as Requirement R9. This is necessary to ensure that the
standard complies with paragraph 94 of FERC Order No. 896, which (as noted in the Technical Rationale) states that resource adequacy is not in scope
for this project.
Likes

0

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0

Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment

No

The wording of Requirement R11 is unclear. In light of NERC’s retirement of the functional model, referring to a “registered entity” instead of a
“functional entity” would be clearer. Alternatively, if Requirement R11 is only intended to require provision of the assessment results to Transmission
Planners and Planning Coordinators, Requirement R11 should be revised to explicitly reference these two types of entities.
Likes

0

Dislikes

0

Response
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

No

Document Name
Comment
NV Energy supports the intent of Requirement R11 but suggest replacing “functional entity” with registered entity because functional entity is not a
defined term, while registered entity makes it clear Extreme Temperature Assessment results are to be shared on a need to know basis with registered
entities that they have enacted a non-disclosure agreement.
Likes

0

Dislikes

0

Response
Wayne Guttormson - SaskPower - 1
Answer

No

Document Name
Comment
Support the MRO NSRF and EEI comments.
Likes

0

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0

Response
Amy Wilke - American Transmission Company, LLC - 1
Answer
Document Name
Comment

No

We would prefer language similar to TPL-001-5.1 R8 requiring distribution of the Extreme Temperature Assessment results to adjacent PCs and TPs:
“Each responsible entity, as identified in Requirement R1, shall distribute its Extreme Temperature Assessment results to adjacent Planning
Coordinators and adjacent Transmission Planners within 90 calendar days of completing its Extreme Temperature Assessment, and to any functional
entity that has a reliability related need and submits a written request for the information within 30 days of such a request.”
Likes

0

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0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

No

Document Name
Comment
“See comments submitted by the Edison Electric Institute”
Likes

0

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0

Response
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

No

Document Name
Comment
NIPSCO supports the comments provided by ReliabilityFirst, CHPD, and WPP.
Likes

0

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0

Response
Colby Galloway - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment

No

Southern Company supports the intent of Requirement R11 but suggests replacing “functional entity” with Registered Entity because functional entity is
not a defined term, while registered entity makes it clear Extreme Temperature Assessment results are to be shared on a need-to-know basis with
Registered Entities that have executed a non-disclosure agreement.
Likes

0

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0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

No

Document Name
Comment
Duke Energy agrees with and endorses EEI comments.
Likes

0

Dislikes

0

Response
Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer

No

Document Name
Comment
AECI supports comment provided by Georgia Transmission Corporation
Likes

0

Dislikes

0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer
Document Name
Comment

No

We support EEI's comments.
Likes

0

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0

Response
Katrina Lyons - Georgia System Operations Corporation - 4
Answer

No

Document Name
Comment
GSOC supports Georgia Transmission Corporation's comments:
•
•

With the nature of this evaluation, it appears appropriate to distribute the assessment and CAP to specific entities such as operators, owners,
and impacted planning entities.
More specifics on metrics that constitute a valid reliability-related need is needed.

Likes

0

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0

Response
Brittany Millard - Lincoln Electric System - 5
Answer

No

Document Name
Comment
LES supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
Likes

0

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0

Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer
Document Name
Comment

No

•
•

With the nature of this evaluation, it appears appropriate to distribute the assessment and CAP to specific entities such as operators, owners,
and impacted planning entities.
More specifics on metrics that constitute a valid reliability-related need is needed.

Likes

0

Dislikes

0

Response
Glen Farmer - Avista - Avista Corporation - 5
Answer

No

Document Name
Comment
EEI supports the intent of Requirement R11 but suggest replacing “functional entity” with registered entity because functional entity is not a defined
term, while registered entity makes it clear Extreme Temperature Assessment results are to be shared on a need-to-know basis between registered
entities that have executed a non-disclosure agreement.
Likes

0

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0

Response
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer

No

Document Name
Comment
LG&E and KU agrees with EEI's comments.
Likes

0

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0

Response
Kristine Martz - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment

No

EEI supports the intent of Requirement R11 but suggest replacing “functional entity” with registered entity because functional entity is not a defined
term, while registered entity makes it clear Extreme Temperature Assessment results are to be shared on a need-to-know basis between registered
entities that have executed a non-disclosure agreement.
Likes

0

Dislikes

0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

No

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and Midwest Reliability Organization's NERC
Standards Review Forum (MRO NSRF) on question 6
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0

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0

Response
Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst Ballot
Body Member and Proxies
Answer

No

Document Name
Comment
RF believes a timeframe of 30 calendar days would be more appropriate.
Likes

0

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0

Response
Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer
Document Name

No

Comment
MPC supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
Likes

1

Dislikes

Lakeland Electric, 1, Watt Larry
0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

No

Document Name
Comment
Oncor would like for “functional entity” to be defined and limited to PCs only. We share the concerns of the Western Power Pool. It may be burdensome
for a responsible entity to reply to requests from “any functional entity" that claims it has a reliability related need to receive our Extreme Temperature
Assessment results.
Likes

0

Dislikes

0

Response
Leslie Hamby - Southern Indiana Gas and Electric Co. - 3,5,6 - RF
Answer

No

Document Name
Comment
Southern Indiana Gas & Electric Company d/b/a CenterPoint Energy Indiana South (SIGE) recommends the following changes:
•
•
•

Modify “60” to “90” calendar days to align with TPL-001-5.1, R8, Part 8.1
Add “NERC” to functional entity for clarity
Add “documented” for clarity

SIGE’s recommended changes are illustrated below:
R11. Each responsible entity, as identified in Requirement R1, shall provide its Extreme Temperature Assessment results within 90 calendar days of a
request to any NERC registered functional entity that has a documented reliability related need and submits a written request for the information.
Likes

0

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Response

0

Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
Please refer to Question 1 comments.
Likes

0

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0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

No

Document Name
Comment
TPL-001-5 requires sharing the results of its Planning Assessment results to adjacent PCs and adjacent TPs within 90 calendars of completing the
Assessment. Therefore, FirstEnergy requests the Drafting Team view the 60-day timeframe under R11 to update to 90 calendar days to be consistent
with TPL-005.
Likes

0

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0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

No

Document Name
Comment
Black Hills Corporation is aligned with EEI’s comments. EEI supports the intent of Requirement R11 but suggest replacing “functional entity” with
registered entity because functional entity is not a defined term, while registered entity makes it clear Extreme Temperature Assessment results are to
be shared on a need to know basis with registered entities that they have enacted a non-disclosure agreement.
Likes

0

Dislikes
Response

0

Michael Whitney - Northern California Power Agency - 3, Group Name NCPA
Answer

No

Document Name
Comment
NO, These assessment should be performed by the Regional Entities. There appears to be too much room for coordination issues having one
Transmission Planner (TP) or Planning Coordinator (PC) having to rely on other TPs or PCs to meet their requirement deadlines.
Likes

0

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0

Response
Lauren Giordano - Lauren Giordano On Behalf of: Dennis Sismaet, Northern California Power Agency, 4, 6, 3, 5; Marty Hostler, Northern
California Power Agency, 4, 6, 3, 5; Michael Whitney, Northern California Power Agency, 4, 6, 3, 5; - Lauren Giordano
Answer

No

Document Name
Comment
NO, These assessment should be performed by the Regional Entities. There appears to be too much room for coordination issues having one
Transmission Planner (TP) or Planning Coordinator (PC) having to rely on other TPs or PCs to meet their requirement deadlines.
Likes

0

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0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

No

Document Name
Comment
Given the timeframe of this study, it will be difficult to know when a new study is available for an entity to submit a written request. At minimum, a
notification the study has been completed could be warranted. Such language exists currently for TPL-001-5.1 and may be similarly leveraged for the
less frequent TPL-008 assessment. For example: “Each responsible entity, as identified in R1, shall distribute its Extreme Temperature Assessment
results to adjacent Planning Coordinators and adjacent Transmission Planners within 90 calendar days of completing its Extreme Temperature
Assessment and within 60 calendar days of a request to any functional entity that has a reliability related need and submits a written request for the
information”.

Likes

0

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0

Response
Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
Entergy recommends changing wording of “has a reliability related need” with “has a documented reliability related need”.
Likes

0

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0

Response
Kevin Conway - Western Power Pool - 4
Answer

No

Document Name
Comment
What is the technical justification for R11? The Transmission Planners should provide their assessments to it's TOP(s), BA(s), RP(s), RC, and PC since
they are all directly affected by the assessment results. The results of the assessment may be considered confidential and shouldn't be distributed an
further than what is necessary. R11, as currently worded, there will be a need for the entity to monitor, track, and potentially address comments
resulting from entities requesting a copy of the assessment results. This administratively complicates the need for an assessment and introduces
administrative compliance risk.
Likes

0

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0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments.

Likes

0

Dislikes

0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Texas RE requests clarification of the phrase “reliability related need”.
Likes

0

Dislikes

0

Response
Kinte Whitehead - Exelon - 3
Answer

Yes

Document Name
Comment
Exelon does not have any objections to the proposed language for Requirement R11.
Likes

0

Dislikes

0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer

Yes

Document Name
Comment
R11: “Responsible entity” should be defined in the Applicability section or should replace with “Each Planning Coordinator, in conjunction with its
Transmission Planner(s)...”). Suggest replacing 4.1 to “Responsible Entity” instead of “Functional Entity”.
Likes
Dislikes

0
0

Response
Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon does not have any objections to the proposed language for Requirement R11.
Likes

0

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0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

Yes

Document Name
Comment
We agree it is vital to have close coordination amongst all responsible entities during the assessment study period.
Likes

0

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0

Response
David Jendras Sr - Ameren - Ameren Services - 3
Answer

Yes

Document Name
Comment
None.
Likes

0

Dislikes
Response

0

Junji Yamaguchi - Hydro-Quebec (HQ) - 5
Answer

Yes

Document Name
Comment
R11: “Responsible entity” should be defined in the Applicability section or should replaced with “Each Planning Coordinator, in conjunction with its
Transmission Planner(s)...” ). Suggest to replace 4.1 to “Responsible Entity” instead of “Functional Entity”.
Likes

0

Dislikes

0

Response
Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer

Yes

Document Name
Comment

ISO supports the “upon request” aspect of the requirement.
Likes

0

Dislikes

0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza
Answer

Yes

Document Name
Comment
R11: “Responsible entity” should be defined in the Applicability section or should replaced with “Each Planning Coordinator, in conjunction with its
Transmission Planner(s)...” ). Suggest to replace 4.1 to “Responsible Entity” instead of “Functional Entity”.
Likes

0

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0

Response
Lenise Kimes - City and County of San Francisco - 1,5 - WECC

Answer

Yes

Document Name
Comment
No comments.
Likes

0

Dislikes

0

Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

Yes

Document Name
Comment
MH is OK with sharing the results upon request if there is a reliability related need.
Likes

0

Dislikes

0

Response
Catrina Martin - Archer Energy Solutions, LLC - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO,WECC, Group Name SPP RTO
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Robert Jones - Seattle City Light - 1,3,4,6
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Michele Tondalo - United Illuminating Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Richard Vendetti - NextEra Energy - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Joshua London - Eversource Energy - 1, Group Name Eversource

Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Israel Perez - Israel Perez On Behalf of: Mathew Weber, Salt River Project, 3, 1, 6, 5; Matthew Jaramilla, Salt River Project, 3, 1, 6, 5; Thomas
Johnson, Salt River Project, 3, 1, 6, 5; Timothy Singh, Salt River Project, 3, 1, 6, 5; - Israel Perez
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Apollonia Gonzales - PNM Resources - 1,3 - WECC,Texas RE
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Mark Flanary - Midwest Reliability Organization - 10
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Isidoro Behar - Long Island Power Authority - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Ben Hammer - Western Area Power Administration - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Robert Follini - Avista - Avista Corporation - 3
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1 - WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jennifer Weber - 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
Response

0

Jeffrey Streifling - NB Power Corporation - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Alison MacKellar - Constellation - 5
Answer
Document Name
Comment
Constellation has no comments
Alison Mackellar on behalf of Constellation Segments 5 and 6
Likes

0

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0

Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Document Name

Comment
How does a responsible entity determine “reliability related need”? Without and parameters an applicable entity could say there is no "reliability related
need" and not have to rspond to any written requests.
Likes

0

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0

Response
Kimberly Turco - Constellation - 6
Answer
Document Name
Comment
Constellation has no comments
Kimberly Turco on behalf of Constellation Segments 5 and 6
Likes

0

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Response

0

7. Do you agree with the proposed TPL-008-1 Table 1? If you do not agree, please provide your recommendation and technical justification.
Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
Entergy recommends that the table should be split into three tables: "Table 1: Performance Criteria", "Table 2: Contingencies", and "Table 3: Steady
State & Stability Footnotes".
Likes

0

Dislikes

0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer

No

Document Name
Comment
On the first page of Table 1, “Corrective Action Plan Required” might be better phrased as “Corrective Action Plan Required for Performance Violations”
or similar.

A fault type (3φ or SLG) should be given for P5 contingencies. To be consistent with TPL-001-5.1, this should be SLG.
Likes

0

Dislikes

0

Response
Thomas Foltz - AEP - 5
Answer

No

Document Name
Comment
The SDT may wish to consider decreasing the 200kv voltage threshold in Table 1 to instead be 100kv. Industry has grown more reliant on generation
which is connected at lower voltages, and contingencies on those lower voltages may be as impactful and even more frequent than at the higher
voltages. AEP sees the potential reliability benefit of including facilities at a lower voltage threshold in Table 1.

Likes

0

Dislikes

0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1 - WECC
Answer

No

Document Name
Comment
Table should include all planning events to avoid confusion with TPL-001-5 Table 1. Information under P3 and P6 could be listed as N/A but it would
avoid confusion.

Likes

0

Dislikes

0

Response
Lauren Giordano - Lauren Giordano On Behalf of: Dennis Sismaet, Northern California Power Agency, 4, 6, 3, 5; Marty Hostler, Northern
California Power Agency, 4, 6, 3, 5; Michael Whitney, Northern California Power Agency, 4, 6, 3, 5; - Lauren Giordano
Answer

No

Document Name
Comment
NO, These assessment should be performed by the Regional Entities. There appears to be too much room for coordination issues having one
Transmission Planner (TP) or Planning Coordinator (PC) having to rely on other TPs or PCs to meet their requirement deadlines.
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0

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0

Response
Michael Whitney - Northern California Power Agency - 3, Group Name NCPA
Answer
Document Name
Comment

No

NO, These assessment should be performed by the Regional Entities. There appears to be too much room for coordination issues having one
Transmission Planner (TP) or Planning Coordinator (PC) having to rely on other TPs or PCs to meet their requirement deadlines.
Likes

0

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0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

No

Document Name
Comment
Black Hills Corporation agrees with EEI’s comments and has no specific recommendations at this time.
While EEI does not yet have specific recommendations for Table 1 at this time, more work is needed to better address the Contingencies and
Performance Criteria for Extreme Temperature Assessments.
Likes

0

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0

Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

No

Document Name
Comment
We strongly support the applicability to 200 kV and above facilities. FERC Order 896 is concerned with the wide-area impacts of extreme temperature
events and the impact of issues with facilities below 200 kV are typically localized. R9 and Table 1 requires the development of Corrective Action Plans
for P1 events where applicable facility ratings are exceeded and steady state voltages are not within limits. This requirement goes beyond the directives
in FERC Order 896. The FERC Order is concerned with cascading, instability, and uncontrolled islanding but not with facility overloads. It would be
prudent for entities to consider Corrective Action Plans for P1 events but the requirement to develop Corrective Action Plans for all P1 issues will lead to
increased costs for extremely low probability and in many cases low consequence events. For example, if an extreme temperature event occurs (low
frequency and low duration), and a P1 event occurs in that time (low probability), then there may be a risk of an element overload. If it can be
demonstrated that the overload does not lead to cascading, instability, or uncontrolled islanding, then the consequence may be reasonable such as a
small degree of loss-of-life in a transformer. The standard, as written, will require the development of expensive Corrective Action Plans for many low
probability, low consequence events and goes beyond FERC Order 896. It is recommended that the text Table 1 be changed under the ‘P1’ column
from “Applicable facility ratings shall not be exceeded. System steady state voltages shall be within acceptable limits as defined in Requirement R5” to
“uncontrolled separation or Cascading, as defined in Requirement R6, shall not occur”.
Likes

0

Dislikes

0

Response
Isidoro Behar - Long Island Power Authority - 1
Answer

No

Document Name
Comment
The first event row in Table 1 specifies “Facility Voltage Level of Contingency”.
Question: is the intent to limit the selection of planning events to events that comprise facilities 200 kV and above? Is so, this should be clarified and/or
mentioned within R7.
The required fault type (3φ or SLG) to be assessed should be specified for P5 contingencies (i.e., SLG – to be consistent with TPL-001-5.1).
Likes

0

Dislikes

0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
Please refer to Question 1 comments.
Likes

0

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0

Response
Leslie Hamby - Southern Indiana Gas and Electric Co. - 3,5,6 - RF
Answer

No

Document Name
Comment
Southern Indiana Gas & Electric Company d/b/a CenterPoint Energy Indiana South (SIGE) supports the recommend Table 1 changes provided by MRO
NERC Standards Review Forum (NSRF) which include:

•
•
•

in the Facility Voltage Level of Contingency row, change the commas to colons,
in the Facility Voltage Level of Contingency row, clarify what is meant by “reference voltage,”
in the Stability Performance Criteria row, clarify what is meant by “initialization.”

Additionally, SIGE request clarification as to why TPL-008’s Table 1 footnotes differ from TPL-001-5.1.
Likes

0

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0

Response
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA believes Table 1 would be appropriate if the P0 benchmark planning base case has all transmission elements in service. However, if P0 case
already includes multiple transmission elements out of service, it is likely CAPs for P0 or any P1 contingency would be cost-prohibitive. Reliability of
system operations under outage conditions is addressed in the Operating Horizon, where loss of load is allowed. Lessons learned from the previous
extreme weather events inform us that it is inevitable to lose a lot of load due to the impact of the event itself. Additionally, BPA highly recommends that
P5 not be included in Table 1 as part of the required studies because extreme weather conditions expose outdoor EHV elements and do not affect
protective relaying.
Likes

0

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0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

No

Document Name
Comment
To avoid confusion with TPL-001-5 Table 1, we recommend that new categories (not P0-P7) should be used in the new TPL-008-1 Standard. Also,
TPL-008-1 Table 1, Category P4 has a footnote #10 in the Category column that is not included or defined in the footnotes.
Likes

0

Dislikes
Response

0

Lenise Kimes - City and County of San Francisco - 1,5 - WECC
Answer

No

Document Name
Comment
• Table 1 – The performance requirements in Table 1 allow for the use of NCLL, but there does not appear to be any limit placed the amount of
NCLL that can be used. Some entities have a maximum amount of NCLL included in their Cascading criteria and/or other planning criteria, but some
entities do not.
o For entities that do not have a maximum amount of NCLL specified, does this mean that they can mitigate any issues with unlimited use of NCLL?
o If so, studying P1, P2, P4, P5 and P7 events would merely tell us how much load would be shed. Capital projects would never be required for P1,
unless some other part of the defined Cascading criteria is violated.
o Should there be some type of maximum NCLL limit for these events or do we just want to rely on the individual Cascading criteria of each PC and TP
entity?
• Table 1 - Table 1 appears to have a cut and paste issue. The title bar includes “(Planning Events and Extreme Events)”, but extreme events are
not defined or otherwise referenced in TPL-008. We recommend removing “and Extreme Events” from the title bar of Table 1.
• We strongly suggest removing P5 from Table 1 for multiple reasons. See R7 and R10 comments.
Likes

0

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0

Response
Israel Perez - Israel Perez On Behalf of: Mathew Weber, Salt River Project, 3, 1, 6, 5; Matthew Jaramilla, Salt River Project, 3, 1, 6, 5; Thomas
Johnson, Salt River Project, 3, 1, 6, 5; Timothy Singh, Salt River Project, 3, 1, 6, 5; - Israel Perez
Answer

No

Document Name
Comment
SRP disagrees with the proposed TPL-008- Table 1. Would it be possible to simply reference TPL-001 table 1 instead? If not, every time we adjust or
make modifications to TPL-001 Standard, we are going to need to open both Standards with a SAR.
Likes

0

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0

Response
Joshua London - Eversource Energy - 1, Group Name Eversource

Answer

No

Document Name
Comment
A fault type for P5 contingencies is needed.
Likes

0

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0

Response
Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer

No

Document Name
Comment
MPC supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
Likes

1

Dislikes

Lakeland Electric, 1, Watt Larry
0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

No

Document Name
Comment
No, Evergy supports and incorporates by reference the comments of the Midwest Reliability Organization's NERC Standards Review Forum (MRO
NSRF) on question 7
Likes

0

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0

Response
Kristine Martz - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment
While EEI does not yet have specific recommendations for Table 1 at this time, more work is needed to better address the Contingencies and
Performance Criteria for Extreme Temperature Assessments.
Likes

0

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0

Response
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer

No

Document Name
Comment
LG&E and KU does not support the proposed Table 1 Contingencies and Performance Requirements and recommend the following changes:
1) The voltage level of applicability should be Facilities at 300 kV or higher, which are designated as extra-high voltage (EHV) Facilities in TPL-001
Table 1. As the proposed TPL-008 mirrors TPL-001 events, it should use the same line of distinction as is used in TPL-001. Many entities will have
existing processes and automation developed to distinguish between high voltage (HV) and EHV events. While the Technical Rationale does not
provide an explanation as to why the analysis is limited to a subset of the BES, a 300 kV threshold appropriately identifies events with possible
widespread impacts.
2) Interruption of Firm Transmission Service should be explicitly permitted in Table 1 where Non-consequential Load Loss is allowed.
3) Planning Events P4, P5, and P7 should be removed from Table 1. The Drafting Team correctly notes in the Technical Rationale that these events are
“less likely to occur compared to P0 and P1 Contingencies” and that “the Extreme Temperature Assessment already addresses low-probability system
conditions.”
The requirement to evaluate these events when no corrective action is required is unreasonable since the likelihood of the events occurring during
extreme system conditions is extremely low, the evaluation of possible mitigation actions is unlikely to result in corrective actions, and because the
evaluation requirements for more likely scenarios (known outages, loss of an element with a long lead spare) is limited to no more than category P0, P1
and P2 events. Furthermore, while some event categories are relatively straightforward to simulate, category P5 events can be exceedingly tedious to
perform. These events also often represent highly unlikely events that are significantly less probable than category P3 or P6 events.
The evaluation of events in categories P0, P1, and P2 represent a reasonable level of analysis for the unlikely extreme conditions represented in the
cases. These events also appropriately consider events that are likely to be monitored for in operational scenarios.
Likes

0

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0

Response
Richard Vendetti - NextEra Energy - 5

Answer

No

Document Name
Comment
See comments in #4 and #5
Likes

0

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0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza
Answer

No

Document Name
Comment
•
•
•

On the first page of Table 1, “Corrective Action Plan Required” might be better phrased as “Corrective Action Plan Required for Performance
Violations” or similar.
A fault type (3φ or SLG) should be given for P5 contingencies. To be consistent with TPL-001-5.1, this should be SLG.
Category P3 seems to be missing from the table.

Likes

0

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0

Response
Glen Farmer - Avista - Avista Corporation - 5
Answer

No

Document Name
Comment
While EEI does not yet have specific recommendations for Table 1 at this time, more work is needed to better address the Contingencies and
Performance Criteria for Extreme Temperature Assessments.

Likes

0

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0

Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford

Answer

No

Document Name
Comment
•
•
•

Consider separating the current Table 1 into separate, appropriately labeled tables.
For the “Facility Voltage Level of Contingency” row, this does not fit within the table under the P event designations. Consider moving to a
footnote section.
“Any common structure that includes a Facility 200kV and above” should be defined within a specific P-event definition (such as P7). As
currently worded, it appears to apply to all P events. Additionally, it is appropriate for the responsible entity to determine the specific common
structure to assess as opposed to “any” common structure.

Likes

0

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0

Response
Brittany Millard - Lincoln Electric System - 5
Answer

No

Document Name
Comment
LES supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
Likes

0

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0

Response
Katrina Lyons - Georgia System Operations Corporation - 4
Answer

No

Document Name
Comment
GSOC supports Georgia Transmission Corporation's comments:
•
•
•

Likes

Consider separating the current Table 1 into separate, appropriately labeled tables.
For the “Facility Voltage Level of Contingency” row, this does not fit within the table under the P event designations. Consider moving to a
footnote section.
“Any common structure that includes a Facility 200kV and above” should be defined within a specific P-event definition (such as P7). As
currently worded, it appears to apply to all P events. Additionally, it is appropriate for the responsible entity to determine the specific common
structure to assess as opposed to “any” common structure.
0

Dislikes

0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

No

Document Name
Comment
We support EEI's comments.
Likes

0

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0

Response
Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer

No

Document Name
Comment
AECI supports comment provided by Georgia Transmission Corporation
Likes

0

Dislikes

0

Response
Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer

No

Document Name
Comment
In Table 1 there is no fault type for P5. This should probably be SLG

Additionally, the SRC recommends that the drafting team either include the full set of footnotes from TPL-001-5.1 Table 1 or clarify why
TPL-008 contains only a limited subset of the footnotes to Table 1.
Likes

0

Dislikes

0

Response
Junji Yamaguchi - Hydro-Quebec (HQ) - 5
Answer

No

Document Name
Comment
On the first page of Table 1, “Corrective Action Plan Required” might be better phrased as “Corrective Action Plan Required for Performance Violations”
or similar.

A fault type (3φ or SLG) should be given for P5 contingencies. To be consistent with TPL-001-5.1, this should be SLG.

Category P3 seems to be missing from the table.
Likes

0

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0

Response
David Jendras Sr - Ameren - Ameren Services - 3
Answer

No

Document Name
Comment
Ameren believes Table 1 performance criteria does not clearly identify applicability. In the Steady State Performance Criteria, it is not clear whether it
applies to all of the BES or just BES elements 200kv and above.
Likes

0

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0

Response
Colby Galloway - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name

No

Comment
The Corrective Action Plan Requirement for P1 events on already extreme conditions and benchmark events is excessive and operating guides should
be an appropriate solution. P1 events should be covered under R10 instead of R9. Southern Company believes that P2, P4, P5 and P7 events are not
appropriate for such a high forecasted load period. P2, P4, P5, and P7 events are unnecessarily extreme conditions to assess on already extreme
cases and load forecasts and should not be included in the scope of analysis. This is especially true for P5 which, under certain circumstances, can look
like total loss of the station events.
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0

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0

Response
Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer

No

Document Name
Comment
Take into consideration labeling Table 1 separately. In addition, for all P events, the phrase "Any Common structure that includes a Facility 200kV and
above" needs to be clarified because the word "any" could be interpreted differently.
Likes

0

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0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

No

Document Name
Comment
Table 1 – The performance requirements in Table 1 allow for the use of NCLL, but there does not appear to be any limit placed the amount of NCLL that
can be used. Some entities have a maximum amount of NCLL included in their Cascading criteria and/or other planning criteria, but some entities do
not.
For entities that do not have a maximum amount of NCLL specified, does this mean that they can mitigate any issues with unlimited use of NCLL?
If so, studying P1, P2, P4, P5 and P7 events would merely tell us how much load would be shed. Capital projects would never be required for P1,
unless some other part of the defined Cascading criteria is violated.
Should there be some type of maximum NCLL limit for these events or do we just want to rely on the individual Cascading criteria of each PC and TP
entity?

Table 1 - Table 1 appears to be mislabeled. The title bar includes “(Planning Events and Extreme Events)”, but extreme events are not defined or
otherwise referenced in TPL-008. We recommend removing “and Extreme Events” from the title bar of Table 1.
We strongly suggest removing P5 from Table 1 for multiple reasons. See R7 and R10 comments.
Likes

0

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0

Response
Robert Jones - Seattle City Light - 1,3,4,6
Answer

No

Document Name
Comment
The table should be reformatted and split into two tables. In the top half, titling the first column “event” doesn’t make sense. The second half appears to
be just a recreation of the TPL-001-5 table 1 and should be separate.
Likes

0

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0

Response
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

No

Document Name
Comment
NIPSCO supports the comments provided by Entergy, AEP, and BPA.
Likes

0

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0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment

No

“See comments submitted by the Edison Electric Institute”
Likes

0

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0

Response
Daniel Gacek - Exelon - 1
Answer

No

Document Name
Comment
Exelon agrees with EEI that more work is needed to better address the Contingencies and Performance Criteria for the Extreme Temperature
Assessments.
We offer the following suggestions:
Need clarification in Table 1 (page 9) regarding “any common structure that includes a Facility 200kV and above” The way this is written it includes
common structure contingencies that include Facilities that are below 200kV. This seems odd since only singles greater than 200kV are included.
Suggest “200kV and above Facilities on any common structure” and apply it to only P7 contingencies. Additionally, the first page of Table 1 is formatted
differently than the second page. Perhaps Table 1 should be split into a Table 1.1 (Performance Criteria) and Table 1.2 (Contingency Category)
Furthermore, the first row starting with “Facility Voltage Level…” doesn’t fit the table format. “Facility Voltage Level…” isn’t an Event. These notes would
be better applied as footnotes.
Table 1 (page 10) “Initial Condition” is labeled as “Normal System,” which is confusing because this isn’t the system as it normally is but the system as it
is modeled under an extreme temperature event. Suggest “System per benchmark planning case identified in R4.”
Likes

0

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0

Response
Amy Wilke - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
ATC generally supports the MRO NSRF comments, and wants to emphasize that it would be helpful to have the standard document that monitored
facilities should still generally include all BES facilities, but contingencies should be those 200 kV and above.
Likes
Dislikes

0
0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer

No

Document Name
Comment
On the first page of Table 1, “Corrective Action Plan Required” might be better phrased as “Corrective Action Plan Required for Performance Violations”
or similar.

A fault type (3φ or SLG) should be given for P5 contingencies. To be consistent with TPL-001-5.1, this should be SLG.

Category P3 seems to be missing from the table.
Likes

0

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0

Response
Kinte Whitehead - Exelon - 3
Answer

No

Document Name
Comment
Exelon agrees with EEI that more work is needed to better address the Contingencies and Performance Criteria for the Extreme Temperature
Assessments.
We offer the following suggestions:
Need clarification in Table 1 (page 9) regarding “any common structure that includes a Facility 200kV and above” The way this is written it includes
common structure contingencies that include Facilities that are below 200kV. This seems odd since only singles greater than 200kV are included.
Suggest “200kV and above Facilities on any common structure” and apply it to only P7 contingencies. Additionally, the first page of Table 1 is formatted
differently than the second page. Perhaps Table 1 should be split into a Table 1.1 (Performance Criteria) and Table 1.2 (Contingency Category)
Furthermore, the first row starting with “Facility Voltage Level…” doesn’t fit the table format. “Facility Voltage Level…” isn’t an Event. These notes would
be better applied as footnotes.
Table 1 (page 10) “Initial Condition” is labeled as “Normal System,” which is confusing because this isn’t the system as it normally is but the system as it
is modeled under an extreme temperature event. Suggest “System per benchmark planning case identified in R4.”
Likes

0

Dislikes

0

Response
Wayne Guttormson - SaskPower - 1
Answer

No

Document Name
Comment
Support the MRO NSRF and EEI comments.
Likes

0

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0

Response
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

No

Document Name
Comment
While NV Energy does not yet have specific recommendations for Table 1 at this time, more work is needed to better address the Contingencies and
Performance Criteria for Extreme Temperature Assessments.
Likes

0

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0

Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT recommends the following clarifications to Table 1:
-

in the Facility Voltage Level of Contingency row, change the commas to colons,

-

in the Facility Voltage Level of Contingency row, clarify what is meant by “reference voltage,” and

-

in the Stability Performance Criteria row, clarify what is meant by “initialization.”

Additionally, ERCOT recommends that the drafting team either include the full set of footnotes from TPL-001-5.1 Table 1 or clarify why TPL-008
contains only a limited subset of the footnotes to Table 1.

Finally, consistent with ERCOT’s comments on the need for Requirement R9 to clarify that Load shed is allowed to establish a solvable P0 system
condition, ERCOT recommends that Table 1 be revised to contain the same clarification as Requirement R9. This is necessary to ensure that the
standard complies with paragraph 94 of FERC Order No. 896, which (as noted in the Technical Rationale) states that resource adequacy is not in scope
for this project.
Likes

0

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0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

No

Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments.
Likes

0

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0

Response
Adrian Harris - Adrian Harris On Behalf of: Bobbi Welch, Midcontinent ISO, Inc., 2; - Adrian Harris, Group Name RTO/ISO Council Standard
Review Committee Project 2023-07 TPL-008
Answer

No

Document Name
Comment
The SRC recommends the following clarifications to Table 1:
•
•
•

in the Facility Voltage Level of Contingency row, change the commas to colons,
in the Facility Voltage Level of Contingency row, clarify what is meant by “reference voltage,” and
in the Stability Performance Criteria row, clarify what is meant by “initialization.”

Additionally, the SRC recommends that the drafting team either include the full set of footnotes from TPL-001-5.1 Table 1 or clarify why TPL-008
contains only a limited subset of the footnotes to Table 1.The SRC also requests that the drafting team confirm that Table 1 will be limited to 200 kV and

above facilities and not include contingencies below 200 kV, as this could miss contingency events below 200 kV that could be limiting to the 200 kV
and up system.
Finally, consistent with the SRC’s comments on the need for Requirement R9 to clarify that Load shed is allowed to establish a solvable P0 system
condition, the SRC recommends that Table 1 be revised to contain the same clarification as Requirement R9. This is necessary to ensure that the
standard complies with paragraph 94 of FERC Order No. 896, which (as noted in the Technical Rationale) states that resource adequacy is not in scope
for this project.
IESO Abstains from Question 7
Likes

0

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0

Response
Catrina Martin - Archer Energy Solutions, LLC - 5
Answer

No

Document Name
Comment
Table 1 – The performance requirements in Table 1 allow for the use of NCLL, but there does not appear to be any limit placed the amount of NCLL that
can be used. Some entities have a maximum amount of NCLL included in their Cascading criteria and/or other planning criteria, but some entities do
not.
o For entities that do not have a maximum amount of NCLL specified, does this mean that they can mitigate any issues with unlimited use of NCLL?
o If so, studying P1, P2, P4, P5 and P7 events would merely tell us how much load would be shed. Capital projects would never be required for P1,
unless some other part of the defined Cascading criteria is violated.
o Should there be some type of maximum NCLL limit for these events or do we just want to rely on the individual Cascading criteria of each PC and TP
entity?

Table 1 - Table 1 appears to have a cut and paste issue. The title bar includes “(Planning Events and Extreme Events)”, but extreme events are not
defined or otherwise referenced in TPL-008. We recommend removing “and Extreme Events” from the title bar of Table 1.
We strongly suggest removing P5 from Table 1 for multiple reasons. See R7 and R10 comments.
Likes

0

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0

Response
Adrian Andreoiu - BC Hydro and Power Authority - 1, Group Name BC Hydro
Answer

No

Document Name
Comment
Likes

0

Dislikes

0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

Yes

Document Name
Comment
TPL-001-5.1 Table 1 includes ‘BES Level’ in-line with the P1-P7 events, as well as Interruption of Firm Transmission Service and whether NonConsequential Load Loss is allowed. The information is generally captured in TPL-008 but having it in a similar table to TPL-001-5.1 could help for
consistency between planning standards and allow for less searching for this information elsewhere in TPL-008. Similarly, the “notes” at the beginning
of TPL-008’s Table 1 are generally footnotes in the TPL-001-5.1 Table 1. While TPL-008’s Table 1 works, functional alignment to how the information is
laid out in TPL-001-5.1 would be appreciated as well.
FERC ultimately did not indicate a required set of contingencies to be considered, leaving this to the SDT. However, in its commentary, FERC Order
896 seemed to highlight those contingencies that could be more related to extreme weather. It is not clear how or if the SDT assessed the weather
relation to contingencies in its Technical Rationale discussion. Does the SDT have specific thoughts or considerations, or is the intent to pass this on to
the applicable entities to make such determinations? In consideration of future Table 1 event selections, thoughts from the SDT on the relation between
extreme weather and contingency selection would be appreciated.
Likes

0

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0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
Comment
No Additional Comments.
Likes

0

Dislikes
Response

0

Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

Yes

Document Name
Comment
Oncor would like to know the technical justification for only calling out BES 200kV and above instead of using BES 100kV and above.
Likes

0

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0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Suggest the DT ensures footnotes and numbering in Table 1 are consistent. I.e., Table 1 category P4 contains a footnote #10, however footnote #10 is
missing from the table on page 12.
Likes

0

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0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
None.
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Kevin Conway - Western Power Pool - 4

Answer

Yes

Document Name
Comment
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0

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0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
Comment
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0

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0

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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
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0

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0

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Robert Follini - Avista - Avista Corporation - 3
Answer

Yes

Document Name
Comment
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0

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0

Response
Ben Hammer - Western Area Power Administration - 1
Answer

Yes

Document Name
Comment
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0

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0

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Mark Flanary - Midwest Reliability Organization - 10
Answer

Yes

Document Name
Comment
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0

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0

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Apollonia Gonzales - PNM Resources - 1,3 - WECC,Texas RE
Answer

Yes

Document Name
Comment
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0

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0

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Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment
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0

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0

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Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst Ballot
Body Member and Proxies
Answer

Yes

Document Name
Comment
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0

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0

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Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

Yes

Document Name
Comment
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0

Dislikes

0

Response
Michele Tondalo - United Illuminating Co. - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

Yes

Document Name
Comment
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0

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0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer

Yes

Document Name
Comment
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0

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0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

Yes

Document Name
Comment
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0

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0

Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO,WECC, Group Name SPP RTO
Answer

Yes

Document Name
Comment
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0

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0

Response
Kimberly Turco - Constellation - 6
Answer
Document Name
Comment
Constellation has no comments
Kimberly Turco on behalf of Constellation Segments 5 and 6

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Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Document Name
Comment
In general, yes but there may be some confusion as there are two parts to the Table. Again, this may be an opportunity to leverage what is done in
TPL-001 and accent it accordingly for an Extreme Temperature Assessment.
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Alison MacKellar - Constellation - 5
Answer
Document Name
Comment
Constellation has no comments
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE noticed that Table 1 is applicable to BES level 200 kV and above. The webinar recording, however, mentioned that the TP and PC should be
monitoring the entire BES, not just 200 kV and above. Texas RE requests the Table 1 language clarify that the entire BES be monitored.

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0

8. The Standard Drafting Team (SDT) is proposing a phased-in implementation plan approach. Do you agree with the proposed phased-in
timeframes? If you do not agree, please provide your recommendation and technical justification.
Catrina Martin - Archer Energy Solutions, LLC - 5
Answer

No

Document Name
Comment
If R9 is intended to include the construction of capital projects, there should be additional time allowed for construction of those projects after the
completion of the first Extreme Temperature Assessment study. An additional 5 years is suggested for CAP’s for R9 that involves capital investment.
Likes

0

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0

Response
Adrian Harris - Adrian Harris On Behalf of: Bobbi Welch, Midcontinent ISO, Inc., 2; - Adrian Harris, Group Name RTO/ISO Council Standard
Review Committee Project 2023-07 TPL-008
Answer

No

Document Name
Comment
In general, the SRC supports the phased-in approach of the proposed implementation plan. That said, the SRC requests the SDT establish a “date
certain” by which the ERO must publish its “approved benchmark library” envisioned under R2. The SRC suggests this be completed within 12 months
of the effective date of TPL-008-1. This will allow planning entities at least 48 months after the ERO benchmark library is published to come into
compliance with proposed requirements R2-R6. As the ERO may not be subject to the Implementation Plan, the SRC defers to NERC and the SDT to
structure the required completion date for the benchmark library in an appropriate manner.
•

The SRC asks the SDT to share how the ERO plans to maintain ongoing updates to the benchmark event library, including the planned update
schedule as well as the underlying criteria, approach and assumptions.

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Michael Goggin - Grid Strategies LLC - 5
Answer
Document Name
Comment

No

The draft Implementation Plan proposes that requirements R7-R11, which require the Extreme Temperature Assessment and any resulting Corrective
Action Plan, do not take effect until more than 6 years after the Standard is approved by FERC. This unnecessary delay is contrary to FERC’s directive
in Order 896 and the urgent importance of planning for extreme heat and cold events.
NERC’s 2023 State of Reliability Overview concluded that “extreme weather events continue to pose the greatest risk to reliability due to the increase in
frequency, footprint, duration, and severity.” FERC Order 896 was also clear that the increasing frequency and magnitude of extreme weather events
“have created an urgency to address the negative impact of extreme weather on the reliability of the Bulk-Power System” (at paragraphs 21-22).
Waiting until after 2030 to address the largest threat to grid reliability does not make sense. Such a delay is also unnecessary, as entities responsible
for TPL-008 already conduct nearly all of the elements of TPL-008 today to comply with TPL-001. TPL-008 effectively requires running similar analyses
as TPL-001, but for extreme heat and cold scenarios. As a result, it should be straightforward for responsible entities to modify their existing planning
practices to incorporate the two additional scenarios.
This unnecessary delay is also at odds with FERC’s directive in Order 896. At paragraph 188, FERC directed “NERC to propose an implementation
timeline for the new or modified Reliability Standard, with implementation beginning no later than 12 months after the effective date of a Commission
order approving the proposed Reliability Standard.” Under the draft Implementation Plan, the only requirement of TPL-008 that comes close to falling
within the 12-month timeline FERC directed is compliance with R1, which begins “the first day of the first calendar quarter that is twelve (12) months
after the effective date of the applicable governmental authority’s order approving the standard.”
More importantly, R1 is only the requirement that “Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall determine and
identify each entity’s individual and joint responsibilities for performing the studies needed to complete the Extreme Temperature Assessment,” and as
such is a minor procedural step towards implementing the actual Extreme Temperature Assessment and any resulting Corrective Action Plan in R7R11. As noted above, those meaningful requirements do not begin until more than 6 years after the standard is approved by FERC. To comply with
FERC’s directive, the drafting team should require compliance with R7-R11 to begin within 12 months of FERC approval of the standard, and the interim
steps in R2-R6 should also be moved up from the Implementation Plan’s proposed deadline of 36 months after the effective date of the standard.
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Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

No

Document Name
Comment
NV Energy does not agree with making Requirement R1 effective on the effective date of TPL-008 because this requirement includes the development
of processes that currently do not exist. Beyond this change, we have no other objections to the proposed Implementation Plan.
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0

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0

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Wayne Guttormson - SaskPower - 1
Answer

No

Document Name
Comment
Support the MRO NSRF and EEI comments.
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0

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0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

No

Document Name
Comment
Texas RE noticed that the phased-In Compliance Dates descriptions do not match the implementation diagram. The verbiage in the implementation
plan says the following:
Phased In Compliance Dates
Effective Date = 12 months after the FERC Order
R1 = Effective Date of TPL-008-1
R2, R3, R4, R5, R6 = Effective Date + 36 months
R7, R8, R9, R10, R11 = Effective Date + 60 months

The diagram in the implementation plan shows the following:
R1 = Effective Date of TPL-008-1 (12 months after the FERC Order)
R2, R3, R4, R5, R6 = Effective Date for TPL-008-1 + 24 months
R7, R8, R9, R10, R11 = Effective Date for TPL-008-1 + 48 months

Texas RE requests the implementation plan descriptions and diagram be aligned. In particular, subsequent compliance activities should be consistently
linked to the Standard Effective Date, which is 12 months following the first calendar quarter after the FERC Order approving the standard. As such, the
chart should be adjusted or the narrative description shortened to reference the implementation period from the effective date.

Additionally, Requirement R8 states that the Extreme Temperature Assessment shall be done once every five calendar years. In the past, there has
been confusion as to whether the first time a periodic activity is done by the effective date/compliance date or within the timeframe specified in the
requirement of the compliance date. In this case, should the first Extreme Temperature Assessment be done by the compliance date or within five

years of the compliance date? In the past, the term “initial performance” has been used in the implementation plan to indicate the first time an activity in
a periodic requirement is to be done. Texas RE requests the implementation plan clarify when the first assessment shall be completed, and generally
recommends establishing an explicit initial performance date upon the effective date of the requirement to avoid delaying compliance obligations an
additional five years.
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Kinte Whitehead - Exelon - 3
Answer

No

Document Name
Comment
Exelon supports EEI’s suggestion regarding Requirement 11.
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0

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0

Response
Daniel Gacek - Exelon - 1
Answer

No

Document Name
Comment
Exelon supports EEI’s suggestion regarding Requirement 11.
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0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment

No

“See comments submitted by the Edison Electric Institute”
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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

No

Document Name
Comment
NIPSCO supports the comments provided by Entergy, WPP, FE, WAPA, CMS Energy, and WECC.
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0

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0

Response
Robert Jones - Seattle City Light - 1,3,4,6
Answer

No

Document Name
Comment
It is unknown when the standard will be approved and go into effect. For R1, utilities should be given more time. Maybe 6 months after the standard
goes into effect. The implementation timeline for other requirements is fair.
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0

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0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

No

Document Name
Comment
In general, ITC supports the phased-in approach of the proposed implementation plan. That said, the ITC requests the SDT establish a “date certain” by
which the ERO must publish its “approved benchmark library” envisioned under R2. ITC suggests this be completed within 12 months of the effective

date of TPL-008-1 as detailed below. This will allow planning entities at least 24 months after the ERO benchmark library is published to come into
compliance with proposed requirements R2-R6.

Alternative is to make the Implementation Plan effective dates for R2-R6 due no sooner than 24 months or 36 months after the benchmark cases are
available and R7-11 due no sooner than 48 months or 60 months after the benchmark cases are available.
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Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

No

Document Name
Comment
If R9 is intended to include the construction of capital projects, there should be additional time allowed for construction of those projects after the
completion of the first Extreme Temperature Assessment study. An additional 5-10 years is suggested for CAP’s for R9 that involves capital
investment.
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0

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0

Response
Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer

No

Document Name
Comment
ISO-NE will reserve its decision on the phased in implementation until after a “benchmark event” list is posted.
Typically ISO will support a phased in implementation.
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0

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0

Mike Magruder - Avista - Avista Corporation - 1
Answer

No

Document Name
Comment
We support EEI's comments.
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0

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0

Response
Brittany Millard - Lincoln Electric System - 5
Answer

No

Document Name
Comment
LES supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
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0

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0

Response
Glen Farmer - Avista - Avista Corporation - 5
Answer

No

Document Name
Comment
EEI does not agree with making Requirement R1 effective on the effective date of TPL-008 because this requirement includes the development of
processes that currently do not exist. If the benchmark event library is maintained outside of the Standard, the implementation plan should not be
initiated until the library is fully established and populated.
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0

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0

Response
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF

Answer

No

Document Name
Comment
LG&E and KU agrees with EEI's comments.
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0

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0

Response
Alison MacKellar - Constellation - 5
Answer

No

Document Name
Comment
It appears ability to comply is completely dependent on having an "approved benchmark library maintained by the Electric Reliability Organization "
However, implementation plan is strictly calendar based and divorced from the establishment of the approved benchmark library. Details of the
benchmark library are not found in either the Std or the Technical Rationale , and the ERO apparently has no obligation to create a library. Suggest
Mitigation Plan, other than R1, be keyed to the library creation. Also suggest putting in Tech Rationale links or references where details of the library
may be found, the process used to select the events, how the library will be maintained and controlled, etc
Alison Mackellar on behalf of Constellation Segments 5 and 6
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0

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0

Response
Kristine Martz - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment
EEI does not agree with making Requirement R1 effective on the effective date of TPL-008 because this requirement includes the development of
processes that currently do not exist. If the benchmark event library is maintained outside of the Standard, the implementation plan should not be
initiated until the library is fully established and populated.
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0
0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

No

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and Midwest Reliability Organization's NERC
Standards Review Forum (MRO NSRF) on question 8
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0

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Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer

No

Document Name
Comment
MPC supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
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0

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0

Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
If the standard gets approved, we will need more implementation time due to other new studies that have to be implemented soon as the results of other
NERC projects.
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0
0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

No

Document Name
Comment
Oncor agrees with statement from Entergy that the timeline should not start until the ERO has developed the benchmark event library. Because of the
complexity of the required study, the proposed standard is written to employ a five-year process. Final implementation of the proposed standard should
be five years after the ERO has developed the benchmark event library.
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0

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0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

No

Document Name
Comment
Minnesota Power supports MRO’s NERC Standards Review Forum’s (NSRF) comments.
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0

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0

Response
Lenise Kimes - City and County of San Francisco - 1,5 - WECC
Answer

No

Document Name
Comment
If R9 is intended to include the construction of capital projects, there should be additional time allowed for construction of those projects after the
completion of the first Extreme Temperature Assessment study. An additional 5 years is suggested for CAP’s for R9 that involved capital investment.
Likes
Dislikes

0
0

Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer

No

Document Name
Comment
The timing is extensive and based on the TPL-001 requirements already in place and does not appear necessary with a few caveats—selection of the
benchmark cases and applying the cases. In general some things are already in place (extreme heat in most places increases load---may impact
Facility Ratings). How the process is done for an Extreme Temperature Assessment may not vary much from today’s efforts. Not sure why R7 would
be delayed as Contingencies are “ordinary” efforts for planning engineers. In essence, with the extended timeframe, and Extreme Weather Assessment
may not occur for SDT timing, FERC approval, plus the implementation period which would be beyond 2030. To be clear, the Assessment in R8 should
not take an additional 5 calendar years on top on the implementation plan. This Standard, while new, is not a completely new Standrad as a lot of the
actions are already being done through TPL-001 processes today.
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0

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0

Response
Leslie Hamby - Southern Indiana Gas and Electric Co. - 3,5,6 - RF
Answer

No

Document Name
Comment
Southern Indiana Gas & Electric Company d/b/a CenterPoint Energy Indiana South (SIGE) agrees with a phased-in approach for TPL-008; however,
SIGE supports MRO NERC Standards Review Forum’s (NSRF) request for the drafting team to establish a “date certain” by which the ERO must
publish its “approved benchmark library” envisioned under R2. Additionally, SIGE agrees with MRO NSRF recommendation that this be completed
within 12 months of the effective date of TPL-008-1. This will allow planning entities at least 24 months after the ERO benchmark library is published to
come into compliance with proposed requirements R2-R6.
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0

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0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer
Document Name
Comment

No

Please refer to Question 1 comments.
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0

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0

Response
Kimberly Turco - Constellation - 6
Answer

No

Document Name
Comment
It appears ability to comply is completely dependent on having an "approved benchmark library maintained by the Electric Reliability Organization "
However, implementation plan is strictly calendar based and divorced from the establishment of the approved benchmark library. Details of the
benchmark library are not found in either the Std or the Technical Rationale , and the ERO apparently has no obligation to create a library. Suggest
Mitigation Plan, other than R1, be keyed to the library creation. Also suggest putting in Tech Rationale links or references where details of the library
may be found, the process used to select the events, how the library will be maintained and controlled, etc.
Kimberly Turco on behalf of Constellation Segments 5 and 6
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0

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0

Response
Adrian Andreoiu - BC Hydro and Power Authority - 1, Group Name BC Hydro
Answer

No

Document Name
Comment
Given the uncertainties detailed above, BC Hydro is unable to support the proposed implementation plan at this time.
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0

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0

Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
Document Name

No

Comment
Consumers Energy agrees with the comments by WAPA:
WAPA supports the phased-in approach of the proposed implementation plan. However, we request the SDT establish a “date certain” by which the
ERO must publish its “approved benchmark library” envisioned under R2. We suggest this be completed within 12 months of the effective date of TPL008-1 as detailed below. This will allow planning entities at least 24 months after the ERO benchmark library is published to come into compliance with
proposed requirements R2-R6. Such as:
Compliance Date for ERO Benchmark Library under TPL-008-1 Requirement R2:The Electric Reliability Organization (ERO) shall be required (commit
in its filing to FERC) to publish the approved benchmark library for performing the Extreme Temperature Assessments within twelve (12) months after
the effective date of Reliability Standard TPL-008-1.
Also, we request the SDT to share how the ERO plans to maintain ongoing updates to the benchmark event library. Will this be on a continuous basis?
Likes

0

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0

Response
Ben Hammer - Western Area Power Administration - 1
Answer

No

Document Name
Comment
WAPA supports the phased-in approach of the proposed implementation plan. However, we request the SDT establish a “date certain” by which the
ERO must publish its “approved benchmark library” envisioned under R2. We suggest this be completed within 12 months of the effective date of TPL008-1 as detailed below. This will allow planning entities at least 24 months after the ERO benchmark library is published to come into compliance with
proposed requirements R2-R6. Such as:
Compliance Date for ERO Benchmark Library under TPL-008-1 Requirement R2:The Electric Reliability Organization (ERO) shall be required
(commit in its filing to FERC) to publish the approved benchmark library for performing the Extreme Temperature Assessments within twelve (12)
months after the effective date of Reliability Standard TPL-008-1.
Also, we request the SDT to share how the ERO plans to maintain ongoing updates to the benchmark event library. Will this be on a continuous basis?
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0

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0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Document Name

No

Comment
Until scope and direction of TPL-008’s intent is clear, FirstEnergy cannot support the Implementation Plan.
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0

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0

Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

No

Document Name
Comment
This study is the first of its kind where multiple Planning Coordinators must coordinate the selection of the benchmark events and the development of
the benchmark planning cases. Sufficient time is required to ensure thorough coordination between responsible entities in the initial Extreme
Temperature Assessment. This may be possible in allotted time but will be difficult. An additional 24 months is required for R7, R8, R9 and R10 to allow
time for planning, design, construction, and regulatory approvals of Corrective Action Plans.
It is unclear when NERC plans to release the benchmarked planning cases. We recommend that the SDT revise the implementation plan with
information on the benchmark library development plan (for example, within 12 months after FERC approval of the standard).
Likes

0

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0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

No

Document Name
Comment
Black Hills Corporation is in agreement with EEI. EEI does not agree with making Requirement R1 effective on the effective date of TPL-008 because
this requirement includes the development of processes that currently do not exist. Beyond this change, we have no other objections to the proposed
Implementation Plan.
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0

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Response

0

Michael Whitney - Northern California Power Agency - 3, Group Name NCPA
Answer

No

Document Name
Comment
NO, These assessment should be performed by the Regional Entities. There appears to be too much room for coordination issues having one
Transmission Planner (TP) or Planning Coordinator (PC) having to rely on other TPs or PCs to meet their requirement deadlines.
Likes

0

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0

Response
Lauren Giordano - Lauren Giordano On Behalf of: Dennis Sismaet, Northern California Power Agency, 4, 6, 3, 5; Marty Hostler, Northern
California Power Agency, 4, 6, 3, 5; Michael Whitney, Northern California Power Agency, 4, 6, 3, 5; - Lauren Giordano
Answer

No

Document Name
Comment
NO, These assessment should be performed by the Regional Entities. There appears to be too much room for coordination issues having one
Transmission Planner (TP) or Planning Coordinator (PC) having to rely on other TPs or PCs to meet their requirement deadlines.
Likes

0

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0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1 - WECC
Answer

No

Document Name
Comment
Acceptable but should have development of operating procedures instead of CAPs.
Likes

0

Dislikes
Response

0

Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
Entergy believes the timeline should not start until ERO has developed benchmark event library. Because of the complexity of the study, standard is
written as five-year process. Final implementation should be 5 years after the ERO has developed benchmark event library.
Likes

0

Dislikes

0

Response
Kevin Conway - Western Power Pool - 4
Answer

No

Document Name
Comment
The phased-in timeframes seem excessive. 12 months should be sufficient since this type of assessment would be done coincident with TPL-001
assessments.
Likes

0

Dislikes

0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
OPG supports NPCC Regional Standards Committee’s 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 NPCC RSC

Answer

Yes

Document Name
Comment
If the comments above reading “Responsible Entity” are retained, corresponding changes should be made to the VSL table.

If the comment above for R6 regarding “to identify instability, uncontrolled separation, or Cascading” is retained, corresponding changes should be
made to the VSL table.
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0

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0

Response
David Jendras Sr - Ameren - Ameren Services - 3
Answer

Yes

Document Name
Comment
None.
Likes

0

Dislikes

0

Response
Junji Yamaguchi - Hydro-Quebec (HQ) - 5
Answer

Yes

Document Name
Comment
If the comments above reading “Responsible Entity” are retained, corresponding changes should be made to the VSL table.

If the comment above for R6 regarding “to identify instability, uncontrolled separation, or Cascading” is retained, corresponding changes should be
made to the VSL table.
Likes

0

Dislikes

0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
None.
Likes

0

Dislikes

0

Response
Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer

Yes

Document Name
Comment
AECI supports comment provided by Georgia Transmission Corporation
Likes

0

Dislikes

0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza
Answer

Yes

Document Name
Comment
•
•
Likes

If the comments above reading “Responsible Entity” are retained, corresponding changes should be made to the VSL table.
If the comment above for R6 regarding “to identify instability, uncontrolled separation, or Cascading” is retained, corresponding changes should
be made to the VSL table
0

Dislikes
Response

0

Isidoro Behar - Long Island Power Authority - 1
Answer

Yes

Document Name
Comment
Assuming that “development” of a CAP, “sharing” of a CAP and “soliciting feedback” on a CAP as part of R9 does not mean “implementing” a CAP, then
we concur with the phased-in implementation plan approach.
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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

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Comment
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0

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0

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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO,WECC, Group Name SPP RTO
Answer

Yes

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Comment
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0

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Amy Wilke - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment
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Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer

Yes

Document Name
Comment
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0

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0

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Colby Galloway - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

Yes

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Comment
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0

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0

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Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer

Yes

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Comment
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Carver Powers - Utility Services, Inc. - 4
Answer

Yes

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Comment
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0

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0

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Katrina Lyons - Georgia System Operations Corporation - 4
Answer

Yes

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Comment
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0

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Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

Yes

Document Name
Comment
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0

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0

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Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer
Document Name

Yes

Comment
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Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

Yes

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Comment
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Michele Tondalo - United Illuminating Co. - 1
Answer

Yes

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Comment
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Richard Vendetti - NextEra Energy - 5
Answer

Yes

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Comment
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0

Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

Yes

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Comment
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Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst Ballot
Body Member and Proxies
Answer

Yes

Document Name
Comment
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0

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Israel Perez - Israel Perez On Behalf of: Mathew Weber, Salt River Project, 3, 1, 6, 5; Matthew Jaramilla, Salt River Project, 3, 1, 6, 5; Thomas
Johnson, Salt River Project, 3, 1, 6, 5; Timothy Singh, Salt River Project, 3, 1, 6, 5; - Israel Perez
Answer

Yes

Document Name
Comment
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0

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Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer
Document Name

Yes

Comment
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Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

Yes

Document Name
Comment
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Apollonia Gonzales - PNM Resources - 1,3 - WECC,Texas RE
Answer

Yes

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Comment
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Mark Flanary - Midwest Reliability Organization - 10
Answer

Yes

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Comment
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Robert Follini - Avista - Avista Corporation - 3
Answer

Yes

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Comment
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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

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Comment
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Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
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1

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Lakeland Electric, 1, Watt Larry
0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

Yes

Document Name
Comment
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Jeffrey Streifling - NB Power Corporation - 1
Answer

Yes

Document Name
Comment
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Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
Comment
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Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
BPA believes a minimum of five years would be the least amount of time to feasibly implement this standard.
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0

9. Provide any additional comments for the SDT to consider, including the provided technical rationale document, if desired.
Kevin Conway - Western Power Pool - 4
Answer
Document Name
Comment
Extreme temperature events seem to be more frequent and longer in duration than in the past. Entities need to ensure that that they properly plan for
events such as these. The proposed TPL-008 tries to address the need for extreme temperature performance, but doesn't seem to address the
duration, as well as the extreme temperature. The proposed standard also appears to hold Transmission Planners to a level of accountability that the
Planning Coordinator is more appropriately set up to do.
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Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer
Document Name
Comment
Entergy recommends that the time frame for the assessment be stated earlier. It could be written as follows:

“R2: Each responsible entity, as identified in Requirement R1, shall complete an Extreme Temperature Assessment of the Long-Term Planning Horizon
once every five calendar years, using the models and contingencies developed in the following requirements."
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Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Document Name
Comment
NA

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Jeffrey Streifling - NB Power Corporation - 1
Answer
Document Name
Comment
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Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
Document Name
Comment
If the SDT is open to further aligning things with TPL-001-5.1, the TPL-001-5.1 standard addresses outages, spare equipment and associated criteria
for its system assessments, TPL-008-1 does not. This is a potential for a reliability gap. Bad system events typically include pre-existing outages as
part of the contributors to the larger event. Including such things in study work, is a reliability principle. During the 4/12/2024 Industry Webinar, it
sounded like the SDT’s expectation was outages (granted, this is 5-10 years out and typically not a lot of outages are planned out that far) were
included either in the extreme weather case or effected by the use of the Table 1 contingencies. However, in actual operations, the outage is typically a
long-duration event, and the need is to be secure for the next credible contingency event. Therefore, it is recommended the SDT re-consider how
outages and potentially unavailable long lead-time equipment may be considered for the purposes of TPL-008.
Furthermore, while it’s not likely this information is known for such timeframes, it is possible that multiple items could be expected to be out of service or
unavailable. This is a scenario FERC seems to hint at in Order 896, Paragraph 88: “Pursuant to section 215(d)(5) of the FPA, we adopt the NOPR
proposal and direct NERC to require under the new or revised Reliability Standard the study of concurrent/correlated generator and transmission
outages due to extreme heat and cold events in benchmark events as described in more detail below”.
It is thought outages should be included in the benchmark planning case per Order 896, Paragraph 91, in part “…Thus, while generation and
transmission availability and concurrent outages must be included in the benchmark planning case, we defer to NERC to develop the framework and
criteria that responsible entities shall use to represent potential weather-related contingencies”. There is no language currently in TPL-008 that includes
pre-existing outages in the base state, only addressing the contingencies. Instead, the analysis, as currently contemplated, is performed, per Table 1,
from “Normal System”, without outages mentioned elsewhere in TPL-008.
FERC goes on further in Order 896, Paragraph 89 to note “We disagree with comments suggesting that the modeling of concurrent/correlated generator
and transmission outages is unnecessary. As discussed in the NOPR, and reinforced by commenters, the failures of individual generators during
extreme weather events are not independent. Previous extreme weather events have demonstrated that there is a high correlation between generator

outages and cold temperatures, indicating that as temperatures decrease, unplanned generator outages and derates increase. Because of this
correlation, it is necessary that responsible entities evaluate the risk of correlated or concurrent outages and derates of all types of generation resources
and transmission facilities as a result of extreme heat and cold events, as commenters suggest.” This seems to indicate FERC is expecting an analysis
that includes an assessment where there are broader outages than possibly what is contemplated under the current TPL-008 approach.
Another risk not discussed in this document and perhaps is more of a “Benchmark Event” topic, is the dispatch of certain types of resources in the case.
In particular, the Pacific Northwest recently performed an assessment of cold weather conditions and found at load seasonal peaks, wind was typically
around 15% of Pmax, solar at 10% of Pmax, and battery resources may become depleted during multi-day events. Similarly, as observed in the recent
ERCOT events, cold weather may also render certain plants un-usable due to freezing conditions. Here in the Northwest, this may be realized in the
form of a summer case where there is extreme water scarcity (drought) for the hydro system, during the extreme weather event. The risk in studies is
these sorts of resources may be dispatched in an overly optimistic manner if attention is not called to their set up for these sorts of extreme weather
analyses. We would recommend some sort of language in the ERO Benchmark Event process (or RE or PC process if this is changed) to include
consideration of such details to ensure resulting studies are not performed with overly optimistic resource supply. We do not believe (and FERC
acknowledges there is a balance of prescriptiveness vs reliability needs, Order 896, Paragraph 91) these are brought to light in the current support and
discussion of the NERC guidance and material surrounding the proposed TPL-008. These constraints are very real and since the purpose of TPL-008 is
to help entities understand potential future needs to provide resiliency for such events, activities such as considering the unavailability, de-rate, or
decreased output of such resources is warranted.
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Jessica Cordero - Unisource - Tucson Electric Power Co. - 1 - WECC
Answer
Document Name
Comment
The new requirements of this standard should be added to a new version of TPL-001. There are too many instances of double jeopardy. The extreme
winter and summer events could be a new P8 Planning Event in Table 1 of TPL-001 where the performance requirements outlined in this standard are
included.
Provide event templates in next posting.
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Michael Whitney - Northern California Power Agency - 3, Group Name NCPA
Answer
Document Name
Comment

No comment.
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Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
Document Name
Comment
Black Hills Corporation recommends the SDT consider adding language in the proposed TPL-008-1 standard similar to section 2.6 of Requirement R2
of TPL-001-5.1 (see language in quotations below).
Adding this language to the standard will allow for entities to better phase out the new study work required of them over the five year period. Entities
could examine an extreme weather event as a sensitivity for one of the long term planning cases and use that analysis as part of their compliance work
for TPL-008-1.
“2.6. Past studies may be used to support the Planning Assessment if they meet the following requirements:
2.6.1. For steady state, short circuit, or Stability analysis: the study shall be five calendar years old or less, unless a technical rationale can be provided
to demonstrate that the results of an older study are still valid.
2.6.2. For steady state, short circuit, or Stability analysis: no material changes have occurred to the System represented in the study. Documentation to
support the technical rationale for determining material changes shall be included.”
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Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Document Name
Comment
The success of this standard depends heavily on the quality, relevance, severity, and probability of the events in the “approved benchmark library
maintained by the [ERO]”. For example, if the events maintained in the approved benchmark library are severe low probability events, then more
Corrective Action Plans will be required to comply with the standard. This approach, when taken to an extreme, introduces a risk of either over-building
or under-building the Bulk Power System. We recommend that the process to develop benchmark events include a thorough consultation with industry
stakeholders including Canadian entities to ensure that the severity and probability of the events are reasonable.

Once established, it is important to know how ERO plans to maintain the benchmark event library.
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Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Document Name
Comment
FirstEnergy requests the Drafting Team to be consistent with the obligations presented in TPL-008 with the obligations from TPL-001.
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Ben Hammer - Western Area Power Administration - 1
Answer
Document Name
Comment
WAPA would also like the SDT address:
Transparency – how will the process ensure ongoing impacted stakeholder participation in the ERO’s development of future benchmark event cases?
Cost – how will the process limit the potential for infinite costs associated with CAPs (as currently written)?
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Kimberly Turco - Constellation - 6
Answer
Document Name
Comment

Constellation has no comments
Kimberly Turco on behalf of Constellation Segments 5 and 6
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Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
BPA appreciates the efforts of the Standard Drafting Team in developing the FERC mandated standard.
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Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Document Name
Comment
The construct of the Standard and thought process behind it is sound and WECC appreciates the efforts. Additional clarity to avoid confusion and
consideration of possibly duplicative work in TPL-001 may need addressed.
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Lenise Kimes - City and County of San Francisco - 1,5 - WECC
Answer
Document Name
Comment

a) The proposed standard is quite lengthy and is duplicative of much of the TPL-001-5.1 standard. While it is good to have consistency in the
methodology, it does increase the need to update both standards if one of them is updated or it could increase the chances of discrepancies between
TPL-001 and TPL-008. There are at least two possible solutions:
o Consider referencing the relevant parts of the TPL-001-5.1 standard in TPL-008, or
o Modify TPL-001-5.1 to include mandatory sensitivity studies for extreme temperature events that meet the requirements of the proposed TPL-008 with
a frequency of every 5 years. These extreme temperature sensitivities would need to have the modified performance requirements that are currently
included in TPL-008, however.
b) Most (not all) of the VSLs are very drastic/severe (0 to 100 in one step) leaving no room for possible explanations or maybe time delays. For
instance, maybe 36 or 60 months noted in the Implementation Plan are not long enough for some entities, but they meet it at 38 or 62 months. The VSL
table should be reworked to better reflect a more realistic severity of many of these items.

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0

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0

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Israel Perez - Israel Perez On Behalf of: Mathew Weber, Salt River Project, 3, 1, 6, 5; Matthew Jaramilla, Salt River Project, 3, 1, 6, 5; Thomas
Johnson, Salt River Project, 3, 1, 6, 5; Timothy Singh, Salt River Project, 3, 1, 6, 5; - Israel Perez
Answer
Document Name
Comment
In addition to the comment in Question 3, SRP strongly recommends that if industry is not going to be part of the benchmarking approval process, that
the SDT then provide regional examples of both ends of extreme weather events. This way, industry can at least understand the range of the different
benchmarking events that the ERO will be selecting.
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Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
Document Name
Comment
Minnesota Power supports MRO’s NERC Standards Review Forum’s (NSRF) comments.

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Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer
Document Name
Comment
MPC supports comments submitted by the MRO NERC Standards Review Forum (NSRF).
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Stephen Whaite - Stephen Whaite On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Stephen Whaite, Group Name ReliabilityFirst Ballot
Body Member and Proxies
Answer
Document Name
Comment
RF appreciates the efforts of the standards drafting team on this project. While RF has submitted an affirmative vote in the associated ballot event, it
encourages the drafting team to consider the concerns and suggestions outlined in this comment submission.
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Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Midwest Reliability Organization's NERC Standards Review Forum (MRO NSRF)
on question 9

Likes

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Alison MacKellar - Constellation - 5
Answer
Document Name
Comment
Constellation has no additional comments
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Richard Vendetti - NextEra Energy - 5
Answer
Document Name
Comment
NextEra suggests that the NERC standards drafting committee, currently focused on extreme weather analysis, include requirements for each PC & TP
to establish and report acceptable load drop thresholds as part of the standard. It's also crucial to mandate the reporting of these thresholds to relevant
regulatory organizations before a PC & TP incorporates load drops into its corrective action plans.

Moreover, while the likelihood of extreme weather events, particularly cold weather occurrences, combined with a line fault and stuck breaker failure to
operate event may appear low, stuck breakers are significantly more prone to occur during extreme cold events. Considering this heightened risk during
cold weather events, along with the potential for load drop resulting in loss of human life, it's imperative to take into account. Thus, NextEra
recommends that the NERC standards drafting committee, focusing on extreme weather events, strongly consider incorporating breaker failure events,
particularly during PC and TP extreme cold analysis, and mandate the inclusion of mitigations in any corrective action plan

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0

Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer
Document Name
Comment
AZPS recommends that the requirement should be renumbered to reflect the order in which the work is performed (i.e. R5 moves to R2, R6 moves to
R3, R2, moves to R4, R3 moves to R5 and R4 moves to R6)
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Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer
Document Name
Comment
•

In general, the development of an extreme weather benchmark event is reasonable. The difficulty in properly assessing this draft Reliability
Standard is the unknowns around the benchmark events. Whether these events are solely temperature-based or if there is a related electrical
system or resource availability embedded needs to be clarified in the standard language.

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Katrina Lyons - Georgia System Operations Corporation - 4
Answer
Document Name
Comment
GSOC supports Georgia Transmission Corporation's comments:
•

Likes

In general, the development of an extreme weather benchmark event is reasonable. The difficulty in properly assessing this draft Reliability
Standard is the unknowns around the benchmark events. Whether these events are solely temperature-based or if there is a related electrical
system or resource availability embedded needs to be clarified in the standard language.
0

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Response

0

Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Document Name
Comment
AECI supports comment provided by Georgia Transmission Corporation
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Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
Remove “Extreme Events” from Table 1 – Steady State & Stability Performance Footnotes (Planning Events and Extreme Events; Page 12 of 20) since
there isn’t an “Extreme Events” category in the TPL-008-1 standard.
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Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer
Document Name
Comment

While ISO-NE supports the efforts of the SDT and the work that they have done to complete this initial draft quickly, ISO-NE reserves its
determination on the Standard until a complete list of the “benchmark events” is made available.
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0

David Jendras Sr - Ameren - Ameren Services - 3
Answer
Document Name
Comment
Ameren suggests adding these requirements to TPL-001-5 instead of making a new standard to reduce the administrative burden of having to deal with
multiple standards.
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Colby Galloway - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
For these low probability, high load forecast extreme events, Southern Company recommends use of operating guides as an allowable solution.
Investment should not be mandated. Further clarification on the definition and approval of benchmark events is needed within the standard.
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Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer
Document Name
Comment
No additional comments.
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0

Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
Document Name
Comment
The proposed standard is quite lengthy and is duplicative of much of the TPL-001-5.1 standard. While it is good to have consistency in the
methodology, it does increase the need to update both standards if one of them is updated or it could increase the chances of discrepancies between
TPL-001 and TPL-008. There are at least two possible solutions:
Consider referencing the relevant parts of the TPL-001-5.1 standard in TPL-008, or
Modify TPL-001-5.1 to include mandatory sensitivity studies for extreme temperature events that meet the requirements of the proposed TPL-008 with a
frequency of every 5 years. These extreme temperature sensitivities would need to have the modified performance requirements that are currently
included in TPL-008, however.
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0

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0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer
Document Name
Comment
Suggested R2 modifications. R2 – ITC recommends that temperature be added to benchmarks to clarify the scope of the benchmarks being
developed.

Should industry be a part of the vetting and approval process for the temperature benchmarks events?
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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer
Document Name
Comment

A completely new standard is unnecessary to address extreme weather events. This requirement could simply be incorporated into the existing TPL001-5 standard. This incorporation could be accomplished by adding a new P8 category addressing extreme weather events, or an additional
requirement could be added to the existing TPL-001-5 standard requiring review of extreme weather events every five years. Incorporation into one TPL
standard would minimize and streamline the TPL system performance assessment process, while preventing any confusion and duplication that would
be created between the existing TPL-001-5 standard and the proposed TPL-008-1 standard.
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Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
“See comments submitted by the Edison Electric Institute”
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Daniel Gacek - Exelon - 1
Answer
Document Name
Comment
Overall, there are too many unknowns at this time, so Exelon is not able to fully support the current proposed standard. We suggest developing an
additional formal guidance that specifies the creation and selection of the benchmark events.
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Amy Wilke - American Transmission Company, LLC - 1
Answer
Document Name

Comment
ATC generally supports the MRO NSRF comments, and wants to emphasize the question: For "1.2 Evidence Retention” under section “C. Compliance”,
what is meant by “or one complete Extreme Temperature Assessment cycle, whichever is longer”?
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Kinte Whitehead - Exelon - 3
Answer
Document Name
Comment
Overall, there are too many unknowns at this time, so Exelon is not able to fully support the current proposed standard. We suggest developing an
additional formal guidance that specifies the creation and selection of the benchmark events.
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0

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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO,WECC, Group Name SPP RTO
Answer
Document Name
Comment
N/A
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Adrian Harris - Adrian Harris On Behalf of: Bobbi Welch, Midcontinent ISO, Inc., 2; - Adrian Harris, Group Name RTO/ISO Council Standard
Review Committee Project 2023-07 TPL-008
Answer
Document Name

Comment
Other concerns the SRC would like the SDT to address include:
Transparency – As noted in the SRC’s comments regarding Requirement R2, an open and transparent process for establishing and maintaining the
benchmark library is crucial, and the SRC recommends that Planning Coordinators be allowed to submit extreme heat and cold events based on their
historical weather events and statistical analysis for inclusion in the library.
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Response
Catrina Martin - Archer Energy Solutions, LLC - 5
Answer
Document Name
Comment
The proposed standard is quite lengthy and is duplicative of much of the TPL-001-5.1 standard. While it is good to have consistency in the
methodology, it does increase the need to update both standards if one of them is updated or it could increase the chances of discrepancies between
TPL-001 and TPL-008. There are at least two possible solutions:
o Consider referencing the relevant parts of the TPL-001-5.1 standard in TPL-008, or
o Modify TPL-001-5.1 to include mandatory sensitivity studies for extreme temperature events that meet the requirements of the proposed TPL-008
with a frequency of every 5 years. These extreme temperature sensitivities would need to have the modified performance requirements that are
currently included in TPL-008, however.

Most (not all) of the VSLs are very drastic/severe (0 to 100 in one step) leaving no room for possible explanations or maybe time delays. For instance,
maybe 36 or 60 months noted in the Implementation Plan are not long enough for some entities, but they meet it at 38 or 62 months. The VSL table
should be reworked to better reflect a more realistic severity of many of these items.
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0

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0

Comments submitted by MRO NSRF:

Questions
1. Do you agree with the proposed definition of Extreme Temperature Assessment? If you do not agree, please provide your recommendation and, if
appropriate, technical justification.
Yes
No
Comments:
Conceptually, the proposed definition for Extreme Temperature Assessment does not presently appear to present any issues; however, the MRO
NERC Standards Review Forum (NSRF) is unable to fully evaluate the definition without more information regarding the “benchmark events” that will
be key to performing Extreme Temperature Assessments.
Our understanding is that NERC intends to post sample benchmark event(s) on or around July 9, 2024. The MRO NSRF will be able to provide more
definitive feedback once this information is available.

2. Do you agree with the proposed TPL-008-1 Reliability Standard Requirement R1? If you do not agree, please provide your recommendation and,
if appropriate, technical justification.
Yes
No
Comments:
The MRO NSRF supports modeling proposed TPL-008, requirement R1 after TPL-001-5.1, requirement R7 and TPL-007, requirement R1.
3. Do you agree with the proposed TPL-008-1 Reliability Standard Requirement R2 (Benchmark events)? If you do not agree, please provide your
recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
As with the Extreme Temperature Assessment definition, the MRO NSRF is unable to fully evaluate Requirement R2 without being able to see
and evaluate some example(s) of what the ERO intends to include as benchmark events in the library. Full evaluation of this requirement also
requires additional information on how the approved benchmark library managed by the ERO will be established, populated and maintained over
time, including the underlying criteria, approach and assumptions. An open and transparent process is crucial, and the MRO NSRF recommends
that Planning Coordinators be allowed to submit, extreme heat and cold events that are impactful to the reliability of the system based on their
historical weather events and statistical analysis for inclusion in the library.
In addition, the MRO NSRF supports the “responsible entity as identified in requirement R1” language in R2 as it allows flexibility among planning
entities to collectively determine who (e.g., the PC and/or TP) will perform R2.

From an improvement perspective, the MRO NSRF recommends several edits to the text of R2:
•
•

The word “temperature” be added to benchmark events to align with the Extreme Temperature Assessment definition and to clarify the
scope of the benchmarks being developed.
The word “industry” be added to indicate industry needs to be part of the vetting and approval process to ensure that temperature benchmarks
do not result in infeasible construction requirements.

R2. Each responsible entity, as identified in Requirement R1, shall select one extreme heat temperature benchmark event and one extreme cold
temperature benchmark event, from the industry approved benchmark library maintained by the Electric Reliability Organization (ERO)
4. Do you agree with the proposed TPL-008-1 Reliability Standard Requirements R3 – R8 (benchmark planning cases and analyses)? If you do not
agree, please provide your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
The MRO NSRF requests the SDT address the following in requirements R3-R8:
R3: The MRO NSRF requests the SDT clarify obligations when coordinating with neighboring PCs to perform an Extreme Temperature Assessment. If
a PC performs a planning area study for a “selected benchmark event” that only includes a portion of the PC’s footprint (Part 3.1), the SDT should
confirm that the PC and its associated Transmission Planners have satisfied the obligation under R2 for completing an Extreme Temperature
Assessment for either “one extreme heat benchmark event or one extreme cold benchmark event” for that five-calendar year period (R8).
In addition, the MRO NSRF requests the SDT clarify the “process for coordinating the development of benchmark planning cases among impacted
Planning Coordinator(s)”
• How far must an entity go, i.e. are Tier 1 neighbors sufficient or must an entity go further?
• Can coordinating on the model build for a given event satisfy this requirement?
Similarly, Requirement R3 should also be revised to clarify how conflicts will be resolved if different Planning Coordinators within the same
Interconnection have incompatible processes for selecting benchmark events, defining the planning study boundary area, and coordinating with
other impacted entities. This clarification should address scenarios in which three or more impacted, geographically contiguous Planning
Coordinators within the same Interconnection all select different, incompatible benchmark events (as allowed by Requirement R1) to study.
• Does the standard require all PCs to support all alternate PC studies?
• What happens if an entity is unwilling to cooperate?
Finally, since stability issues do not propagate over DC ties, Requirement R3 should be revised to indicate that Planning Coordinators and
Transmission Planners are not required to coordinate with entities in different Interconnections.
R4: The System models shall use data consistent with that provided in accordance with the MOD-032 standard, supplemented by other sources as
needed,…”
The MRO NSRF supports the use of MOD-032 to obtain the necessary data and asks the SDT to consider, does MOD-032 need to be modified to
acquire information unique to TPL-008?
R5: The MRO NSRF has concerns with R5 as it may be duplicative of work that is already occurring under TPL-001-5.1. Specifically, it is unclear
how the criteria for “steady state voltage limits and post-Contingency voltage deviations” under TPL-008, R5 differs from what entities have defined
under TPL-001-5.1, and consequently, it is unclear why Requirement R5 is needed. Please explain.

In addition, it is unclear why Requirement R5 only addresses voltage issues without also addressing thermal issues, as Table 1’s reference to
“facility ratings” would seem to include thermal issues. The absence of any reference to thermal issues in Requirement R5 would seem to imply that
thermal issues (at least those that don’t result in instability, uncontrolled separation, or Cascading) aren’t to be considered. The MRO NSRF
recommends that the drafting team clarify whether this is its intent. A possible method of addressing this ambiguity may be to revise Requirement
R5 to use language along the lines of “operate within the criteria specified in Table 1.”
R6. The MRO NSRF has concerns with R6 as R6 may duplicate work that is already occurring under TPL-001-5.1, PRC-006, and other Reliability
Standards. Therefore, the MRO NSRF asks the SDT to describe the need drivers for R6 by identifying where extreme temperature events have
resulted in system instability, uncontrolled separation, or Cascading.
R7. To clarify that the Extreme Temperature Assessment is limited to the planning study area boundary defined in Part 3.1, the MRO NSRF requests the
SDT modify requirement R7 as follows:
R7. Each responsible entity, as identified in Requirement R1, shall identify Contingencies used in performing the Extreme Temperature Assessment for
each of the event categories in Table 1 that are expected to produce more severe System impacts within the its planning study area boundary defined in
Part 3.1. The rationale for those Contingencies selected for evaluation shall be available as supporting information.
R8. The MRO NSRF recommends that Requirement R8 be revised to clarify whether the case used needs to be a Long-Term case at the time the study is
completed or it just when the case building is completed, as two to three years typically elapse between the completion of the case build and the
completion of the studies that use the case.
5. Do you agree with the proposed TPL-008-1 Reliability Standard Requirements R9 – R10 (CAPs and possible actions)? If you do not agree, please
provide your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
R9. The MRO NSRF observes that R9 requires responsible entities to share their CAPs with, and solicit feedback from, applicable regulatory authorities
or governing bodies responsible for retail electric service issues in all cases. This may extend the amount of time needed for CAP approval.
In addition, for entities that are not subject to an "applicable regulatory authority or governing body" for retail electric service issues, e.g., WAPA, does
R9 apply to them? If that’s the SDT’s intent, the MRO NSRF recommends R9 clarify that non-jurisdictional entities are merely submitting their CAPs to
the regulatory authority solely for the purpose of receiving comments and are not bound by the local regulatory or governing body. See proposed text to
be added to R9 below:
"In the event a non-jurisdictional entity submits a CAP to a regulatory authority or governing body, the submission of the CAP is for informational
purposes, feedback, and comment only. The submission of a CAP by a non-jurisdictional entity to a regulatory authority does not waive jurisdiction,
immunity, or otherwise place the non-jurisdictional entity under the regulatory authority or the governing body."
The MRO NSRF recommends that the drafting team resolve an apparent inconsistency regarding the P0 analysis. Specifically, the technical rationale
appears to suggest that Load shedding is permitted to establish a solvable P0 system condition. However, Requirement R9 and Table 1 do not seem to
allow load shedding for solvable P0 system condition. The MRO NSRF recommends that the drafting team address this by revising Requirement R9 to
explicitly indicate that Load shed is allowed to establish a solvable P0 system condition. This is necessary to ensure that the study can assume sufficient
resources are available in a P0 state. This, in turn, is necessary to prevent the standard from straying into the realm of resource adequacy. As noted in
the Technical Rationale, resource adequacy is not in scope for this project under paragraph 94 of FERC Order No. 896.
Finally, the MRO NSRF recommends the phrase “but the planned System shall continue to meet the performance requirements” be stricken from the
standard, as it is phrased as an operation mandate, which is inappropriate for a standard focused on long-term planning objectives.
R9. “…Revisions to the CAP(s) are allowed in subsequent Extreme Temperature Assessments, but the planned System shall continue to meet the
performance requirements.”

6. Do you agree with the proposed TPL-008-1 Reliability Standard Requirement R11 (Sharing Extreme Temperature Assessment results)? If you do not
agree, please provide your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
The MRO NSRF supports the “upon request” nature of R11 and sharing Extreme Temperature Assessment results with those having a “reliability need.”
That said, the MRO NSRF recommends the following edits for enhanced clarity and alignment as detailed below:
• Modify “60” to “90” calendar days to align with TPL-001-5.1, R8, Part 8.1
• Add “NERC” to functional entity for clarity.
R11. Each responsible entity, as identified in Requirement R1, shall provide its Extreme Temperature Assessment results within 90 60 calendar
days of a request to any NERC registered functional entity that has a reliability related need and submits a written request for the information.
7. Do you agree with the proposed TPL-008-1 Table 1? If you do not agree, please provide your recommendation and technical justification.
Yes
No
Comments:
The MRO NSRF recommends the following clarifications to Table 1:
- in the Facility Voltage Level of Contingency row, change the commas to colons,
- in the Facility Voltage Level of Contingency row, clarify what is meant by “reference voltage,” and in the Stability Performance Criteria row,
clarify what is meant by “initialization.”
The MRO NSRF recommends that the drafting team include the full set of footnotes from TPL-001-5.1 Table 1 or clarify why TPL-008 contains
only a limited subset of the footnotes to Table 1.
Finally, consistent with the MRO NSRF’s comments on the need for Requirement R9 to clarify that Load shed is allowed to establish a solvable
P0 system condition, the MRO NSRF recommends that Table 1 be revised to contain the same clarification as Requirement R9. This is
necessary to ensure that the standard complies with paragraph 94 of FERC Order No. 896, which (as noted in the Technical Rationale) states
that resource adequacy is not in scope for this project.
8. The Standard Drafting Team (SDT) is proposing a phased-in implementation plan approach. Do you agree with the proposed phased-in
timeframes? If you do not agree, please provide your recommendation and technical justification.
Yes
No
Comments:
In general, the MRO NSRF supports the phased-in approach of the proposed implementation plan. That said, the MRO NSRF requests the SDT
establish a “date certain” by which the ERO must publish its “approved benchmark library” envisioned under R2. The MRO NSRF suggests this be
completed within 12 months of the effective date of TPL-008-1. This will allow planning entities at least 24 months after the ERO benchmark library
is published to come into compliance with proposed requirements R2-R6. As the ERO may not be subject to the Implementation Plan, we leave it to
NERC and the SDT to structure the required completion date for the benchmark library in an appropriate manner.



The MRO NSRF asks the SDT to share how the ERO plans to maintain ongoing updates to the benchmark event library, including the planned
update schedule as well as the underlying criteria, approach and assumptions.

Compliance Date for TPL-008-1 Requirements R2, R3, R4, R5, R6
Entities shall not be required to comply with Requirement R2, R3, R4, R5, and R6 until thirty-six (36) months after the effective date of Reliability
Standard TPL-008-1
9. Provide any additional comments for the SDT to consider, including the provided technical rationale document, if desired.
Comments:
Other concerns the MRO NSRF would like the SDT to address include:
Transparency – As noted in the MRO NSRF’s comments regarding Requirement R2, an open and transparent process for establishing and
maintaining the benchmark library is crucial, and the MRO NSRF recommends that Planning Coordinators be allowed to submit extreme heat
and cold events based on their historical weather events and statistical analysis for inclusion in the library.
• Cost – how will the process limit the potential for infinite costs associated with CAPs (as currently written)?
•
For "1.2 Evidence Retention” under section “C. Compliance”, what is meant by “or one complete Extreme Temperature Assessment cycle,
whichever is longer”?
o
for example, should this be defined to a specific period of time, 5 year, 10 years, etc…
•

Summary Response to TPL-008-1 Draft 1
Comments Received

NERC Project 2023-07 Transmission Planning Performance Requirements
for Extreme Weather
July 2024
Comments Received Summary

There were 78 sets of responses, including comments from approximately 179 different people from
approximately 99 companies representing 10 of the Industry Segments. A summary of comments submitted
can be reviewed on the project page.
If you have an interest in joining the distribution list for this project, please reach out to Senior Standards
Developer, Jordan Mallory.
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 Manager of Standards Jamie Calderon (via email) or at (404) 960-0568.

Consideration of Comments

The NERC Project 2023-07 thanks all of industry for your time and comments. The Standard Drafting Team
(SDT) feels that many great points have been provided for the SDT to consider during the drafting phase of
this project. High level themes received from industry are located below (bolded is the high-level theme
followed by the SDT’s response).

Benchmark Events

Many commenters expressed concern that they cannot fully approve the Extreme Temperature Assessment
and definition and TPL-008-1 Standard without having benchmark events information. In addition, some
entities expressed concern about having to agree to a requirement that has yet to be fully developed. Based
on the technical rationale, there is an expectation that the ERO will determine suitability and make available
benchmark events representative of probable futures. Once the initial library of events has been developed,
we would be in a better position to consider support for this requirement.
Drafting team response:
NERC is still committed to providing additional information regarding the criteria used in the development
of this initial population of the benchmark event library, the process for maintaining the library, the process
for entity submitted benchmark events and the criteria for which they will be evaluated for approval, as
well as the future state envisioned for ongoing curation of the library with industry involvement and climate
data SMEs.

RELIABILITY | RESILIENCE | SECURITY

To best assist the team when voting “No” please provide comments specific to the Standard and
requirements that are within scope for the team to address. As NERC is directed by FERC to create the
benchmark event library, it is unclear what improvement to the Standard that the drafting team is able to
make to the Standard draft or definitions.
Subm itting Benchm ark Events P rocess
Entities with an interest in submitting their own benchmark events are seeking a timeframe as to when the
process will be provided to industry.

Drafting team response:
NERC is still committed to providing additional information regarding the criteria used in the development
of this initial population of the benchmark event library, the process for maintaining the library, the process
for entity submitted benchmark events and the criteria for which they will be evaluated for approval, as
well as the future state envisioned for ongoing curation of the library with industry involvement and climate
data SMEs.
The process is expected to be initially posted on the NERC website and will be maintained to ensure it is up
to date. This process is not included within the balloting process and should be considered separately to be
consistent with the balloting process.
R egional Entities to Com plete Assessm ents
Some commenters stated that Regional Entities should be the entity who completes the assessment.

Drafting team response:
Regional Entities are not subject to compliance of standards and thus cannot perform assessment to meet
standard requirements. Planning Coordinators in coordination with Transmission Planners are the
appropriate entities to complete planning assessments.

Definitions

The SDT received comments with proposed updated definitions for consideration. Below provides a highlevel list of what was received.
•

•

Updated proposed terms (no definition updates):


Extreme Weather Assessment



Extreme Temperature Transmission Assessment



Expected Scope Assessment

Request SDT to define the following terms;


Extreme heat and extreme cold temperature benchmark events

Summary Response to TPL-008-1 Draft 1 Comments Received | Project 2023-07 Transmission Planning Performance Requirements for
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Drafting team response:
The SDT appreciates all the proposed term update considerations. It was determined to leave Extreme
Temperature Assessment for many reasons. Those reasons are 1) temperature focuses on this specific
project with regards to extreme cold and heat planning cases being based on temperature; 2) Transmission
is not an appropriate addition to this term as entities are supposed to be looking at generator information
during transmission outages (See Requirement R3); and 3) the definition has been drafted at a high level
for the purpose of specifics that need to be added like steady state, transient stability, etc. which are
mentioned in the requirement.
Regarding extreme heat and extreme cold temperature benchmark events – This will be further explained
in the NERC Process document.

TPL-008-1 Applicability and Standard Requirements

The SDT received comments on Requirements R1 through R11 and Table 1. Below takes a deeper look into
the comments received and the consideration the SDT made.

Requirement R2
Benchmark events

Some comments asked for clarification on the benchmark events development and maintenance process
including the responsible entity, the criteria for the selection of benchmark events and access restrictions
to the library. Some comments also questioned if additional benchmark events can be submitted to the
library.
Drafting team response:
Questions on the benchmark events library will be addressed through a separate process document
provided by the ERO. There will not be an attachment to the standard. Also, the entities will be allowed to
submit benchmark events to the library. Details on the approval process will be included in the process
document.

Compliance Obligation Separation

Some comments questioned who the responsible entity was and raised coordination concerns among the
different entities.
Drafting team response:
Responsible entities are defined in R1. One entity will be chosen as the primary entity. Language was revised
to further clarify this. Replaced ‘Each responsible entity’ with ‘The responsible entity established in R1’.
Some entities may use PC as the primary responsible entity and others may use TP as the primary
responsible entity. The language was drafted to allow for this, Regional Entities and EROs are not applicable
entities and hence will not be allowed to perform the study.

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Number of benchmark events

Some comments questioned if more than one extreme heat benchmark event and one extreme cold
benchmark event can be studied.
Drafting team response:
The standard requires that at least one benchmark heat and one benchmark cold event is studied. The
Responsible Entity can choose to study more than one event if they want to. The language was updated to
say “at least” one event should be studied.

Clarification on “Functional Entities” in the Applicability section

Some comments suggested that the “Functional Entities” in the Applicability section be changed to
“Responsible Entities”.
Drafting team response:
“Functional entities” in the Applicability section could mean the entities outside the Responsible Entities
defined in R1 of the standard. The definition of “Functional Entity” is consistent with the other NERC TPL
standards.

Minor wording changes

Some comments suggested that the word “temperature” be added to R2 when referencing extreme heat
and cold benchmark events.
Drafting team response:
Comment accepted and R2 language was revised accordingly.

Requirement R3

Overlap w ith Other R eliability Standards
Some comments suggested the drafting team should add a provision that would allow work on other
Reliability Standards to cover the requirements specified in TPL-008. Additionally, some suggested the
responsible entity should follow the criteria set forth in FAC-014-3. Finally, some suggested the drafting
team coordinate with Project 2023-06 CIP-014 Risk Assessment Refinement.

Drafting team response:
There are fundamental differences between TPL-001-5.1 and TPL-008 (e.g., TPL-001 has an annual
periodicity while TPL-008 does not and TPL-008 requires broader coordination based on the selected
benchmark temperature events). Nothing in the standard precludes the responsible entity from using
similar information used in other standards to demonstrate compliance with TPL-008. Additionally, the
requirements in TPL-008 do not contradict those in FAC-014-3 nor the CIP-014 drafting team efforts because
they allow the responsible entity to determine the criteria, which may be the same or different than criteria
used in other standards.

Summary Response to TPL-008-1 Draft 1 Comments Received | Project 2023-07 Transmission Planning Performance Requirements for
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All Lines in Service
Some comments suggested P0 should be evaluated with all lines in service as a base case.

Drafting team response:
Line outages may be included in the base case if those outages are consistent with the conditions defined
in the selected benchmark temperate events.
Justification of Contingencies
Some comments questioned how the responsible entity could justify one set of outages versus another.

Drafting team response:
In accordance with Requirement R7, the responsible entity must provide the technical rationale for the
contingencies selected for evaluation. In accordance with the TPL-008 Technical Rationale document, some,
but not all, items to consider when developing the rationale for selecting Contingencies are past studies,
subject matter expert knowledge of the responsible entity’s System (to be supplemented with data or
analysis), and historical data from past operating events.
Adjust Tim eline for I m plem entation of CAPs
Some comments suggested that the implementation plan allow a ten-year period for implementation of
CAPs that require capital investment to construct new facilities.

Drafting team response:
The drafting team did not modify the implementation plan; however, a sub-requirement was added under
Requirement R9 stating that if circumstances beyond the control of the responsible entity prevent the
timely implementation of CAPs, responsible entities may use Non-Consequential Load Loss to address the
issue, provided they document the situation, evaluate alternatives, and record the actions taken.
Differentiation of “Planning Cases” and “System M odels”
Some comments suggested the difference between “planning cases” and “system models” should be
clarified because they are not defined in the NERC Glossary of Terms.

Drafting team response:
The drafting team concluded system models are components that are necessary to include in the
development of benchmark planning cases, which is consistent with NERC Reliability standard TPL-001-5.1.
Clarity on P0 Events
Some comments suggested additional clarity is needed to determine when and if P0 and P1 events are
required.

Drafting team response:
The drafting team concluded the responsible entity must include P0 in the assessment. The TPL-008-1
Technical Rationale document provides further information.

Summary Response to TPL-008-1 Draft 1 Comments Received | Project 2023-07 Transmission Planning Performance Requirements for
Extreme Weather | July 2024
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Requirement R4

M OD-032 Data
Some commenters asked if the drafting team feel it would be necessary to add any additional data to the
table in MOD-032 to complete this work. In addition, some sought clarification on how MOD-032 will allow
for the collection of additional information related to extreme heat and cold events.

Drafting team response:
MOD-032 ensures an adequate means of data collection for transmission planning and requires applicable
registered entities to provide steady-state, dynamic, and short circuit modeling data to their transmission
planner(s) and planning coordinator(s). As outlined in R1 and Attachment 1 of MOD-032, MOD-032 allows
various data collection such as in-service status and capability associated with demand, generation, and
transmission associated with various case types, scenarios, system operating states, or conditions for the
long-term planning horizon. MOD-032 also requires applicable registered entities to provide “other
information requested by the Planning Coordinator or Transmission Planner necessary for modeling
purposes” for each of the three types of data required. Because the drafting team determined the
responsible entities that will be developing benchmark planning cases are limited to planning coordinators
and transmission planners, they will be able to request and receive needed data pursuant to MOD-032.
Thus, the drafting team believes that there is no need to update MOD-032 because it allows planning
coordinators and transmission planners to request any specific data needed for developing and maintaining
benchmark planning cases required in R4 of TPL-008-1.

Requirement R5

Criteria for Therm al Constraints
Some comments questioned why voltage was being referenced but not thermal constraints.

Drafting team response:
The drafting team updated Requirement R5 to include “applicable Facility Ratings.”
Acceptable Deviation R ange
Some comments suggested including an acceptable deviation range or acceptable based on common
industry practice or technical basis as it is currently open-ended as to what criteria is “acceptable.”

Drafting team response:
The drafting team concluded the standard is flexible enough to allow for regional differences throughout
the requirements, which is consistent with Reliability Standard TPL-001-5.1.
Language Change
Some comments suggested changing the language from “shall have criteria” to “shall define and document
criteria” for consistency with Requirement R6.

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Drafting team response:
The drafting team determined that “have” is the appropriate wording for this requirement as the
responsible entity could be receiving this information from somewhere else based on how responsibilities
are established in Requirement R1.
Language Change
Some comments suggested unless some exception is made for FAC-014-3 R6, there may be no further room
possible with respect to operational limits.

Drafting team response:
The drafting team allowed flexibility on how the responsibility entity sets limits.
Use of “System Voltage Lim its”
Some comments suggested using the recently adopted NERC Glossary term “System Voltage Limits.”

Drafting team response:
The drafting team determined “System Voltage Limits” focuses on operations and planning information
may differ. The drafting team concluded to maintain the proposed language consistent with Reliability
Standard TPL-001-5.1.
Coordinated Criteria
Some comments questioned if the Planning Coordinator must ensure all entities are using the same criteria
for acceptable System steady state voltage limits.

Drafting team response:
The drafting team determined some Transmission Planners under a Planning Coordinator could have
different voltage limits. In accordance with Requirement R1, the Planning Coordinator, in conjunction with
its Transmission Planner(s), must determine individual or joint responsibilities.
Docum entation to be used from a different standard
If a TP or PC believes that the work performed for a different standard will cover work required under TPL008, can a provision for this be added to the standard?

Drafting team response:
Provision language does not need to be added to the TPL-008-1 standard. If an entity feels that
documentation from another Reliability Standard, such as TPL-001, is sufficient, the entity can use that
same information for the evidence of TPL-008-1.

Requirement R6

“I nstability, uncontrolled separation, or Cascading” and I R OLs
Some comments questioned if the identification of “instability, uncontrolled separation, or Cascading” are
expected to be different for the Extreme Temperature Assessment relative to Interconnection Reliability
Operating Limits (IROLs).

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Drafting team response:
The drafting team does not specify how instability, uncontrolled separation, or Cascading should be defined.
Additionally, the requirement allows the responsible entity flexibility to determine the criteria or
methodology, which may be the same or different than criteria used in other standards.
Severity of ER O Library Events
Some comments expressed concern that if the events in the ERO library are too severe and lead to a
significant increase in the events that trigger instability, these could be expensive problems to fix.

Drafting team response:
The drafting team determined entities are welcome to develop their own benchmark temperature events
should the ones within the ERO library not suffice. Additionally, per Requirement R9, Corrective Action Plans
are only required for Table 1 P0 or P1 Contingencies.
“I nstability, uncontrolled separation, or Cascading” Boundary
Some comments questioned if entities must identify instability, uncontrolled separation, or Cascading of
the System or the Interconnection.

Drafting team response:
The drafting team added “within an Interconnection” to Requirement R6.
M ultiple Violations for a Single I ssue
Some comments questioned if this is duplicative to TPL-001-5.1 or other standards, and if this will create a
situation where two requirements would be violated for a single issue.

Drafting team response:
The drafting team determined that Reliability Standard TPL-001-5.1 is for standard conditions while TPL008-1 is for extreme conditions (i.e., extreme heat and extreme cold temperature events).
Acceptable Load Loss Thresholds
Some comments suggested entities should be required to establish acceptable load loss thresholds for
addressing thermal overloads identified before utilizing non-consequential load drops as a corrective action
plan.

Drafting team response:
The drafting team determined the responsible entity may choose to define load loss thresholds in its criteria
or methodology, or in coordination with its regulatory authorities or governing bodies. Recognizing regional
variations in requirements, the drafting team finds it impractical to set a maximum limit. Therefore, there
is no set load loss identified in TPL-008; however, Table 1 allows for Non-Consequential Load Loss.

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Requirement R7

Acceptable Load Loss Thresholds
Some entities expressed that R7 should clearly indicate which contingency categories are required.

Drafting team response:
Requirement R7 identifies the contingencies are listed in Table 1.

Requirement R8

Tim efram e Specificity
Some entities expressed concern that R8 may not provide enough specificity regarding the time frame to
be assessed from the Long-Term Transmission Planning Horizon.

Drafting team response
The standard provides flexibility within the standard, which is consistent with other drafting efforts.
R8 requires study be performed minimum every five years for at least one year in the long-term horizon.
The standard requires a minimum, one. Nothing precludes an entity from completing more than one
condition, should it be needed.
M OD-032 Clarity and Need for Sensitivity Analysis
Some entities request clarification on the purpose of sensitivity analyses in sub-part 8.2 and its association
with MOD-032 data collection. Recommend clarity on the necessity of sensitivity analyses and its relation
to data collection from the MOD-032 model build.

Drafting team response
MOD-032 is the appropriate standard to gather data needed for this project scope. Sensitivity studies are
required by FERC order 896.

Requirement R9

R egulatory Burden
Many commenters raised concerns about the requirement to submit CAPs to regulatory authorities,
suggesting it could delay approval, lacks justification, need clearer definitions, and should be limited or
removed.

Drafting team response
The SDT reviewed the comments and determined that the requirement is necessary to address the
directives of Order 896, specifically the directives mentioned in paragraphs 152 and 165.
Allow ing N on-Consequential Load Loss (N CLL) for P 0, Concerns about I nadequate Available
Generation, and Addressing I nconsistencies in R 9
Various entities commented on allowing NCLL (i.e., Load Shed) for P0, addressing inconsistencies between
R9 and the Technical Rationale regarding load shedding requirements for P0. They suggested explicitly
permitting load shedding for solvable P0 system conditions, noting that resource adequacy is not within the

Summary Response to TPL-008-1 Draft 1 Comments Received | Project 2023-07 Transmission Planning Performance Requirements for
Extreme Weather | July 2024
9

scope of TPL-008 as per TR and Order 896, proposed allowing NCLL under extreme weather conditions for
P0, and questioned if NCLL would be allowed for P0 if capital projects or Operating Plans are not completed
before the operating horizon.
Drafting team response
The SDT reviewed the comments and updated the Technical Rationale to ensure consistency with
Requirement R9. Specifically, the SDT removed the discussion on resource adequacy for P0 from the
Technical Rationale for R9, as it is irrelevant to the Corrective Action Plan discussed in R9. Additionally, the
SDT offered guidance on preparing solvable P0 cases in the Technical Rationale for R4 to address concerns
about potential instances where benchmark planning cases and/or sensitivity cases might lack adequate
available generation to meet demand.
The SDT added a sub-requirement under R9 stating that if circumstances beyond the control of the TP or
PC prevent the timely implementation of a Corrective Action Plan, responsible entities may use NonConsequential Load Loss to address the issue, provided they document the situation, evaluate alternatives,
and record the actions taken.
Consistency and Clarity
Comments were made to improve clarity and address inconsistency between R9 and other related
standards (TPL-008, TPL-001), such as Non-Consequential Load Loss and sharing CAPs.

Drafting team response
The SDT reviewed the comments and updated Requirement R9 for consistency and to provide clarity.
Clarity on Sensitivity Analysis
Various commenters questioned the necessity of a Corrective Action Plan for issues identified in sensitivity
analysis, seeking clarity on how sensitivity analysis is handled.

Drafting team response
The SDT revised Requirement R9 to clarify that Corrective Action Plans are not required specifically for
addressing performance requirements related to sensitivity cases.
Proposals R egarding Load Shedding
Some commenters recommended explicitly prohibiting load shedding as a CAP, while other entities
suggested setting a maximum limit for non-consequential load loss.

Drafting team response
The SDT reviewed the comments and emphasizes that non-consequential load loss is explicitly prohibited
for P0 as specified in Table 1 of TPL-008. Recognizing regional variations in requirements, the SDT finds it
impractical to set a maximum limit for non-consequential load loss, leaving it to entities to determine for
other planning events like P1. Additionally, R6 mandates defining and documenting criteria or
methodologies in the Extreme Temperature Assessment to identify instability, uncontrolled separation, or

Summary Response to TPL-008-1 Draft 1 Comments Received | Project 2023-07 Transmission Planning Performance Requirements for
Extreme Weather | July 2024
10

cascading events. The SDT believes that the maximum limit for non-consequential load loss could be
specified within the methodology.

Requirement R10

R easons for R equiring Possible Actions and R estrictions in Creating CAPs
Certain commenters questioned why possible actions are required for P2, P4, P5, and P7 contingencies,
while others disagreed due to limitations in creating CAPs for these contingencies.

Drafting team response
The SDT reviewed the comments and affirms that the Technical Rationale for R10 adequately clarified the
necessity for possible actions. Additionally, it is important to note that TPL-008 sets a baseline to fulfill the
directives from Order 896 and does not prohibit responsible entities from exceeding these requirements.
Clarity and Com m unication on Possible Actions
A commenter questioned what actions the responsible entity intends to take based on the identified
"possible actions." There is uncertainty about how these actions will be executed. In addition, it suggested
that these possible actions should be communicated to the operators so they can prepare necessary plans
and processes accordingly.

Drafting team response
The SDT acknowledges the commenter's concerns regarding implementing 'possible actions' and their
communication to operators. The SDT asserts that Requirement 11 outlines the expected actions,
mandating responsible entities to share Extreme Temperature Assessment results with any functional
entities with reliability-related needs to enhance readiness for extreme temperature events.
Ex clusion of P2, P4, P5, and P7 Contingencies
Some commenters proposed removing P5, citing that extreme weather conditions affect outdoor EHV
elements but do not impact protective relaying. Additionally, other comments suggested excluding P2, P4,
P5, and P7 events from TPL-008.

Drafting team response
The SDT reviewed the comments and updated Requirement 10 and Table 1 to remove the P5 contingency
from TPL-008. The rationale for this decision is detailed in the Technical Rationale of R7.

Requirement R11

Tim eline for Distributing Assessm ent R esults
Some comments questioned if the 60 calendar days was appropriate.

Drafting team response:
The drafting team determined to keep the requirement unchanged as this strikes a good balance between
allowing enough time for the responsible entity to distribute the results and the functional entity requesting
the information to receive them.

Summary Response to TPL-008-1 Draft 1 Comments Received | Project 2023-07 Transmission Planning Performance Requirements for
Extreme Weather | July 2024
11

Distribution of Assessm ent R esults
Some comments questioned if the distribution of the Extreme Temperature Assessment results should be
limited to select registered entities.

Drafting team response:
The drafting team determined to keep the requirement unchanged as it meets the following FERC directive
in FERC Order 896, Paragraph 72: “Further, responsible entities must share the study results with affected
transmission operators, transmission owners, generator owners, and other functional entities with a
reliability need for the studies.” Therefore, the responsible entity must share with any functional entity that
has a reliability related need and submits a written request for the information. Additionally, this is
consistent with other approved NERC Reliability Standards (e.g., TPL-001-5.1 and TPL-007-4).
M etrics for “R eliability R elated Need”
Some comments questioned if metrics should be associated with “reliability related need.”

Drafting team response:
The drafting team determined to keep the requirement unchanged as this is consistent with other approved
NERC Reliability Standards (e.g., TPL-001-5.1 and TPL-007-4).

Table 1

Gram m atical/ Clarifying Changes
Some commenters recommended grammatical/clarifying changes to Table 1.

•

A commenter requested the Facility Voltage Level of Contingency row, change the commas to
colons,

•

A commenter requested the Facility Voltage Level of Contingency row, clarify what is meant by
“reference voltage,”

•

A commenter requested the Stability Performance Criteria row, clarify what is meant by
“initialization.”

•

Many commenters recommended that the contingencies should be updated to 200 kV and above.

•

Strongly suggest removing P5 from Table 1 for multiple reasons.

•

Suggest the DT ensures footnotes and numbering in Table 1 are consistent. I.e., Table 1 category P4
contains a footnote #10, however footnote #10 is missing from the table on page 12.

•

Some commenters said more work is needed to better address the Contingencies and Performance
Criteria for Extreme Temperature Assessments.

Drafting team response:
Please see updated modifications to Table 1 based on comments received and listed above.

Summary Response to TPL-008-1 Draft 1 Comments Received | Project 2023-07 Transmission Planning Performance Requirements for
Extreme Weather | July 2024
12

M onitor Entire BES
Table 1 is applicable to BES level 200 kV and above. The webinar recording, however, mentioned that the
TP and PC should be monitoring the entire BES, not just 200 kV and above. A commenter requests the Table
1 language clarify that the entire BES be monitored.

Drafting team response:
Additional language has been added to the Purpose (Section A) and Requirement R9 to indicate that the
performance criteria is applicable to all the BES.
Non-Consequential Load Loss
Some commenters questioned the performance requirements in Table 1 allow for the use of nonconsequential load loss, but there does not appear to be any limit placed on the amount of nonconsequential load loss that can be used. Some entities have a maximum amount of non-consequential
load loss included in their Cascading criteria and/or other planning criteria, but some entities do not.

In addition, for entities that do not have a maximum amount of NCLL specified, does this mean that they
can mitigate any issues with unlimited use of NCLL?
Drafting team response:
Please see the revised TPL-008-1 Requirement R9 for revised language regarding the Non-Consequential
Load Loss where it is allowed and utilized. In addition, a maximum value for Non-Consequential Load Loss
is not provided in the TPL-008-1 because of regional variances and requirements regarding criteria for
identifying instability, uncontrolled separation, or Cascading.
Footnote Section of Table 1
Some commenters recommend the drafting team either include the full set of footnotes from TPL-001-5.1
Table 1 or clarify why TPL-008-1 contains only a limited subset of the footnotes to Table 1.

Drafting team response:
The Contingencies chosen for TPL-008-1 are different from TPL-001-5.1. TPL-008-1 standard is developed
and organized to be independent from TPL-001-5.1. Based on this, not all footnotes were needed for TPL008-1.

Violation Severity Levels (VSLs)

Some entities expressed concern regarding the severity level for the VSLs.
Drafting team response:
The team encourages entities to review the VSL Guidelines document. When a pass/fail requirement is
drafted, any noncompliance with the requirement will have only one VSL – Severe. Link to guideline
document: VSL Guidelines (Revised) (nerc.com).

Summary Response to TPL-008-1 Draft 1 Comments Received | Project 2023-07 Transmission Planning Performance Requirements for
Extreme Weather | July 2024
13

Implementation Plan

Benchm ark Events
Some entities request a date be established as to when the ERO will have the benchmark event library
published.

Drafting team response:
An ERO Benchmark Event Process document has been published with the TPL-008-1 draft 2 posting. The
ERO benchmark event library will be published and up and running by December 2024. This library will
contain events for the first 5-year iteration of TPL-008-1. Additional time is essentially provided to entities
as the benchmark events will be published and TPL-008-1 will be pending approval from the respective
applicable governmental authorities. In addition, example benchmark event examples have been provided
in a separate document for entities to see what they will be working with to meet the TPL-008-1 Reliability
Standard. Please reference the process document for additional details on how the ERO plans to address
preparing for the next 5-year iteration of benchmark events.
R equirem ent R 1
Many entities disagreed with making Requirement R1 effective on the effective date of TPL-008-1 because
this requirement includes the development of processes that currently do not exist.

Drafting team response:
Per FERC Order 896, Paragraph 7, “we direct NERC to ensure that the proposed new or modified Reliability
Standard becomes mandatory and enforceable beginning no later than 12 months from the effective date
of Commission approval of the new or modified Reliability Standard.” To meet this FERC directive,
Requirement R1 is the most reasonable requirement to meet the 12-month implementation directive. 1
months from the approval date of TPL-008-1 is adequate time to identify individual and joint responsibilities
for completing the Extreme Temperature Assessment. Requirement R3 is when the process should be
developed and implemented, which per the TPL-008-1 Implementation Plan has 36-months. In addition,
there is nothing precluding entities from starting discussion with other PCs and TPs once the petition has
been submitted for approval with the respective governmental authorities.
R equirem ent R 9
Some entities expressed concern that if R9 is intended to include the construction of capital projects, there
should be additional time allowed for construction of those projects after the completion of the first
Extreme Temperature Assessment study.

Drafting team response:
The drafting team did not change the implementation plan; however, Requirement R9.3 was added to
permit the use of Non-Consequential Load Loss as an interim solution, which normally is not permitted in
Table 1, in situations that are beyond the control of the Planning Coordinator or Transmission Planner that
prevent the implementation of a Corrective Action Plan in the required timeframe. The use of NonConsequential Load Loss as an interim solution in this situation is permitted, provided that each responsible
entity documents the situation causing the problem, alternatives evaluated, and takes actions to resolve
the situation. Additionally, Requirement R9.4 was added to permit having revisions to the CAP in

Summary Response to TPL-008-1 Draft 1 Comments Received | Project 2023-07 Transmission Planning Performance Requirements for
Extreme Weather | July 2024
14

subsequent Extreme Temperature Assessments, provided that the planned BES continues to meet the
performance requirements of Table 1.
I m plem entation Plan Diagram
One commenter pointed out that the diagram does not line up with the Implementation Plan Language and
requested the team update it accordingly.

Drafting team response:
Please see the updated diagram in the Implementation Plan, which should provide clarity on any confusion.

Summary Response to TPL-008-1 Draft 1 Comments Received | Project 2023-07 Transmission Planning Performance Requirements for
Extreme Weather | July 2024
15

Public

Reminder
Standards Announcement

Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather
Initial Ballots and Non-binding Poll Open through May 3, 2024
Now Available

Initial ballots for draft one of TPL-008-1 – Transmission System Planning Performance
Requirements for Extreme Temperature Events and non-binding poll of the associated Violation
Risk Factors and Violation Severity Levels are open through 8 p.m. Eastern, Friday, May 3, 2024.
Reminder Regarding Corporate RBB Memberships

Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more
than the one permitted representative in a particular Segment must withdraw the duplicate
membership(s) prior to joining new ballot pools or voting on anything as part of an existing ballot
pool. Contact [email protected] to assist with the removal of any duplicate registrations.
Balloting

Members of the ballot pools associated with this project can log in and submit their votes by accessing
the Standards Balloting and Commenting System (SBS) here.
•

Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.

•

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 ballot results will be announced and posted on the project page. The drafting team will review all
responses received during the comment period and determine the next steps of the project.
For information on the Standards Development Process, refer to the Standard Processes Manual.

RELIABILITY | RESILIENCE | SECURITY

Public

For more information or assistance, contact Standards Developer, Jordan Mallory (via email) or at 404-4797358. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists" from the
"Service" drop-down menu and specify “Project 2023-07 Transmission Planning Performance Requirements
for Extreme Weather observer list” in the Description Box.

North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Ballot Open Reminder
Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather | April 24, 2024

2

Public

Standards Announcement

Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather
Formal Comment Period Open through May 3, 2024
Ballot Pools Forming through April 18, 2024
Now Available

A 45-day formal comment period for draft one of TPL-008-1 – Transmission System Planning
Performance Requirements for Extreme Temperature Events is open through 8 p.m. Eastern,
Friday, May 3, 2024.
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. An unofficial Word
version of the comment form is posted on the project page.
Reminder Regarding Corporate RBB Memberships

Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more
than the one permitted representative in a particular Segment must withdraw the duplicate
membership(s) prior to joining new ballot pools or voting on anything as part of an existing ballot pool.
Contact [email protected] to assist with the removal of any duplicate registrations.
Ballot Pools

Ballot pools are being formed through 8 p.m. Eastern, Thursday, April 18, 2024. Registered Ballot
Body members can join the ballot pools here.
•

Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.

•

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

Limited Disclosure

Next Steps

Initial ballots for the standard and implementation plan, as well as a non-binding poll of the associated
Violation Risk Factors and Violation Severity Levels will be conducted April 24 – May 3, 2024.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Jordan Mallory (via email) or at 404-4797358. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists" from the
"Service" drop-down menu and specify “Project 2023-07 Transmission Planning Performance Requirements
for Extreme Weather observer list” in the Description Box.

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 2023-07 Transmission Planning Performance Requirements for Extreme Weather | March 20, 2024

2

NERC Balloting Tool (/)

Dashboard (/)

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS  
Comment: View Comment Results (/CommentResults/Index/319)
Ballot Name: 2023-07 Transmission Planning Performance Requirements for Extreme Weather TPL-008-1 IN 1 ST
Voting Start Date: 4/24/2024 12:01:00 AM
Voting End Date: 5/3/2024 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 277
Total Ballot Pool: 314
Quorum: 88.22
Quorum Established Date: 5/3/2024 2:03:44 PM
Weighted Segment Value: 18.69
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

89

1

10

0.135

64

0.865

0

4

11

Segment:
2

8

0.6

0

0

6

0.6

0

1

1

Segment:
3

68

1

6

0.1

54

0.9

0

3

5

Segment:
4

18

1

3

0.231

10

0.769

0

1

4

Segment:
5

76

1

9

0.158

48

0.842

0

9

10

Segment:
6

47

1

5

0.135

32

0.865

0

4

6

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

1

0

0

0

0

0

0

1

0

Segment

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

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:
9

0

0

0

0

0

0

0

0

0

Segment:
10

7

0.6

4

0.4

2

0.2

0

1

0

Totals:

314

6.2

37

1.159

216

5.041

0

24

37

Segment

BALLOT POOL MEMBERS
Show

All

Segment

entries

Organization

Search:

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power,
Inc.

Hillary Creurer

Negative

Comments
Submitted

1

Ameren - Ameren
Services

Tamara Evey

Negative

Comments
Submitted

1

American Transmission
Company, LLC

Amy Wilke

Negative

Comments
Submitted

1

APS - Arizona Public
Service Co.

Daniela
Atanasovski

Negative

Comments
Submitted

1

Arizona Electric Power
Cooperative, Inc.

Jennifer Bray

None

N/A

1

Associated Electric
Cooperative, Inc.

Mark Riley

Negative

Comments
Submitted

1

Austin Energy

Thomas
Standifur

Affirmative

N/A

Negative

Comments
Submitted

1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Corporation

Segment

Organization

Voter

1

Balancing Authority of
Northern California

Kevin Smith

1

BC Hydro and Power
Authority

1

Designated
Proxy

NERC
Memo

Affirmative

N/A

Adrian Andreoiu

Negative

Comments
Submitted

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

Negative

Comments
Submitted

1

Black Hills Corporation

Micah Runner

Negative

Comments
Submitted

1

Bonneville Power
Administration

Kamala RogersHolliday

Negative

Comments
Submitted

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Negative

Comments
Submitted

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

None

N/A

1

Central Iowa Power
Cooperative

Kevin Lyons

Negative

Third-Party
Comments

1

City Utilities of Springfield,
Missouri

Michael Bowman

Negative

Third-Party
Comments

1

Colorado Springs Utilities

Corey Walker

Negative

Third-Party
Comments

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dairyland Power
Cooperative

Karrie Schuldt

Negative

Third-Party
Comments

1

Dominion - Dominion
Virginia Power

Elizabeth Weber

Negative

Comments
Submitted

1

Duke Energy

Katherine Street

Negative

Comments
Submitted

1

Edison International Southern California
Edison Company

Robert Blackney

None

N/A

1

Entergy

Brian Lindsey

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Tim Kelley

Ballot

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

Hayden Maples

Negative

Comments
Submitted

1

Evergy

Kevin Frick

1

Eversource Energy

Joshua London

Negative

Comments
Submitted

1

Exelon

Daniel Gacek

Negative

Comments
Submitted

1

FirstEnergy - FirstEnergy
Corporation

Theresa Ciancio

Negative

Comments
Submitted

1

Georgia Transmission
Corporation

Greg Davis

Negative

Comments
Submitted

1

Glencoe Light and Power
Commission

Terry Volkmann

Negative

Third-Party
Comments

1

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Emma Halilovic

Lidija Efremova

Affirmative

N/A

1

Hydro-Quebec (HQ)

Nicolas Turcotte

Chantal Mazza

Negative

Comments
Submitted

1

IDACORP - Idaho Power
Company

Sean Steffensen

None

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Denise Sanchez

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Allie Gavin

Negative

Comments
Submitted

1

JEA

Joseph McClung

Negative

Comments
Submitted

1

KAMO Electric
Cooperative

Micah Breedlove

Negative

Third-Party
Comments

1

Lakeland Electric

Larry Watt

Negative

Third-Party
Comments

1

Lincoln Electric System

Josh Johnson

None

N/A

1

Long Island Power
Authority

Isidoro Behar

Negative

Comments
Submitted

Abstain

N/A

1
Los Angeles Department
faranak sarbaz
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
of Water and Power

Stephen
Stafford

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Lower Colorado River
Authority

Matt Lewis

Affirmative

N/A

1

LS Power Transmission,
LLC

Jennifer
Richardson

None

N/A

1

M and A Electric Power
Cooperative

William Price

Negative

Third-Party
Comments

1

Manitoba Hydro

Nazra Gladu

Negative

Comments
Submitted

1

MEAG Power

David Weekley

Rebika Yitna

Negative

Comments
Submitted

1

Minnkota Power
Cooperative Inc.

Theresa Allard

Andy Fuhrman

Negative

Comments
Submitted

1

Muscatine Power and
Water

Andrew Kurriger

Negative

Third-Party
Comments

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Negative

Third-Party
Comments

1

National Grid USA

Michael Jones

Negative

Third-Party
Comments

1

NB Power Corporation

Jeffrey Streifling

Negative

Comments
Submitted

1

Nebraska Public Power
District

Jamison Cawley

Negative

Third-Party
Comments

1

New York Power Authority

Daniel Valle

Negative

Third-Party
Comments

1

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Negative

Comments
Submitted

1

NiSource - Northern
Indiana Public Service
Co.

Alison Nickells

Negative

Comments
Submitted

1

Northeast Missouri
Electric Power
Cooperative

Brett Douglas

Negative

Third-Party
Comments

Negative

Third-Party
Comments

1

OGE Energy - Oklahoma
Terri Pyle
Gas and Electric Co.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Segment

Organization

Voter

1

Omaha Public Power
District

Doug Peterchuck

1

Oncor Electric Delivery

Byron Booker

1

Orlando Utilities
Commission

1

Designated
Proxy

Ballot

NERC
Memo

Negative

Third-Party
Comments

Negative

Comments
Submitted

Aaron Staley

Affirmative

N/A

OTP - Otter Tail Power
Company

Charles Wicklund

Negative

Third-Party
Comments

1

Pacific Gas and Electric
Company

Marco Rios

Negative

Comments
Submitted

1

Platte River Power
Authority

Marissa Archie

Negative

Third-Party
Comments

1

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Negative

Comments
Submitted

1

Portland General Electric
Co.

Brooke Jockin

Abstain

N/A

1

PPL Electric Utilities
Corporation

Michelle
McCartney
Longo

Negative

Comments
Submitted

1

PSEG - Public Service
Electric and Gas Co.

Karen Arnold

Negative

Third-Party
Comments

1

Public Utility District No. 1
of Chelan County

Diane E Landry

Negative

Comments
Submitted

1

Public Utility District No. 1
of Snohomish County

Alyssia Rhoads

Negative

Comments
Submitted

1

Public Utility District No. 2
of Grant County,
Washington

Joanne Anderson

None

N/A

1

Sacramento Municipal
Utility District

Wei Shao

Tim Kelley

Affirmative

N/A

1

Salt River Project

Matthew
Jaramilla

Israel Perez

Negative

Comments
Submitted

Negative

Comments
Submitted

1
Santee Cooper
Chris Wagner
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Broc Bruton

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

SaskPower

Wayne
Guttormson

Negative

Comments
Submitted

1

Seminole Electric
Cooperative, Inc.

Kristine Ward

None

N/A

1

Sempra - San Diego Gas
and Electric

Mohamed
Derbas

Negative

Third-Party
Comments

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Negative

Comments
Submitted

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Negative

Third-Party
Comments

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

None

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

None

N/A

1

Tennessee Valley
Authority

David Plumb

Negative

Comments
Submitted

1

Tri-State G and T
Association, Inc.

Donna Wood

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Abstain

N/A

1

Unisource - Tucson
Electric Power Co.

Sam Rugel

Negative

Comments
Submitted

1

VELCO -Vermont Electric
Power Company, Inc.

Randall Buswell

Abstain

N/A

1

Western Area Power
Administration

Ben Hammer

Negative

Comments
Submitted

1

Xcel Energy, Inc.

Eric Barry

Negative

Third-Party
Comments

2

California ISO

Darcy O'Connell

Abstain

N/A

2

Electric Reliability Council
of Texas, Inc.

Kennedy Meier

Negative

Comments
Submitted

None

N/A

2

Independent Electricity
Helen Lainis
System
Operator
© 2024 - NERC Ver 4.2.1.0
Machine
Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

2

ISO New England, Inc.

John Pearson

Keith Jonassen

Negative

Comments
Submitted

2

Midcontinent ISO, Inc.

Bobbi Welch

Adrian Harris

Negative

Third-Party
Comments

2

New York Independent
System Operator

Gregory Campoli

Negative

Third-Party
Comments

2

PJM Interconnection,
L.L.C.

Thomas Foster

Negative

Third-Party
Comments

2

Southwest Power Pool,
Inc. (RTO)

Joshua Phillips

Negative

Comments
Submitted

3

AEP

Leshel Hutchings

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras Sr

Negative

Comments
Submitted

3

APS - Arizona Public
Service Co.

Jessica Lopez

Negative

Comments
Submitted

3

Arkansas Electric
Cooperative Corporation

Ayslynn Mcavoy

None

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Negative

Comments
Submitted

3

Austin Energy

Lovita Griffin

Affirmative

N/A

3

Avista - Avista
Corporation

Robert Follini

Negative

Comments
Submitted

3

BC Hydro and Power
Authority

Ming Jiang

Negative

Comments
Submitted

3

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Joseph Amato

Negative

Comments
Submitted

3

Black Hills Corporation

Josh Combs

Negative

Comments
Submitted

3

Bonneville Power
Administration

Ron Sporseen

Negative

Comments
Submitted

3

Buckeye Power, Inc.

Tom Schmidt

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Elizabeth Davis

Carly Miller

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Negative

Third-Party
Comments

3

City Utilities of Springfield,
Missouri

Jessica
Morrissey

Negative

Third-Party
Comments

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Negative

Comments
Submitted

3

Colorado Springs Utilities

Hillary Dobson

Negative

Third-Party
Comments

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Virginia Power

Bill Garvey

Negative

Comments
Submitted

3

DTE Energy - Detroit
Edison Company

Marvin Johnson

Abstain

N/A

3

Duke Energy - Florida
Power Corporation

Marcelo
Pesantez

Negative

Comments
Submitted

3

Edison International Southern California
Edison Company

Romel Aquino

Negative

Comments
Submitted

3

Entergy

James Keele

Negative

Comments
Submitted

3

Evergy

Marcus Moor

Negative

Comments
Submitted

3

Eversource Energy

Vicki O'Leary

Negative

Comments
Submitted

3

Exelon

Kinte Whitehead

Negative

Comments
Submitted

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Negative

Comments
Submitted

3

Georgia System
Operations Corporation

Scott McGough

None

N/A

3

Great River Energy

Negative

Third-Party
Comments

Michael
Brytowski
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Segment

Organization

Voter

3

Imperial Irrigation District

George Kirschner

3

JEA

3

Designated
Proxy

NERC
Memo

Affirmative

N/A

Marilyn Williams

Negative

Comments
Submitted

Lakeland Electric

Steven Marshall

Negative

Comments
Submitted

3

Lincoln Electric System

Sam Christensen

Negative

Comments
Submitted

3

Los Angeles Department
of Water and Power

Fausto Serratos

Abstain

N/A

3

M and A Electric Power
Cooperative

Gary Dollins

Negative

Third-Party
Comments

3

Manitoba Hydro

Mike Smith

Negative

Comments
Submitted

3

MEAG Power

Roger Brand

Negative

Comments
Submitted

3

MGE Energy - Madison
Gas and Electric Co.

Benjamin Widder

Negative

Third-Party
Comments

3

Muscatine Power and
Water

Seth Shoemaker

Negative

Third-Party
Comments

3

National Grid USA

Brian Shanahan

Negative

Third-Party
Comments

3

Nebraska Public Power
District

Tony Eddleman

Negative

Third-Party
Comments

3

New York Power Authority

David Rivera

Negative

Third-Party
Comments

3

NextEra Energy - Florida
Power and Light Co.

Karen Demos

Negative

Comments
Submitted

3

NiSource - Northern
Indiana Public Service
Co.

Steven
Taddeucci

Negative

Comments
Submitted

3

Northern California Power
Agency

Michael Whitney

Negative

Comments
Submitted

Negative

Third-Party
Comments

3

NW Electric Power
Heath Henry
Cooperative,
Inc.
© 2024 - NERC Ver 4.2.1.0
Machine
Name: ATLVPEROWEB01

Denise Sanchez

Ballot

Rebika Yitna

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Negative

Third-Party
Comments

3

Omaha Public Power
District

David Heins

Negative

Third-Party
Comments

3

OTP - Otter Tail Power
Company

Wendi Olson

Negative

Third-Party
Comments

3

Pacific Gas and Electric
Company

Sandra Ellis

Negative

Comments
Submitted

3

Platte River Power
Authority

Richard Kiess

Negative

Third-Party
Comments

3

PNM Resources - Public
Service Company of New
Mexico

Amy
Wesselkamper

Negative

Comments
Submitted

3

Portland General Electric
Co.

Mayra Franco

Abstain

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

Christopher
Murphy

Negative

Third-Party
Comments

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Negative

Comments
Submitted

3

Sacramento Municipal
Utility District

Nicole Looney

Tim Kelley

Affirmative

N/A

3

Salt River Project

Mathew Weber

Israel Perez

Negative

Comments
Submitted

3

Santee Cooper

Vicky Budreau

Negative

Comments
Submitted

3

Seminole Electric
Cooperative, Inc.

Marc Sedor

None

N/A

3

Sempra - San Diego Gas
and Electric

Bryan Bennett

Negative

Third-Party
Comments

3

Sho-Me Power Electric
Cooperative

Jarrod Murdaugh

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Snohomish County PUD
No. 1

Holly Chaney

Negative

Comments
Submitted

3

Southern Company Alabama Power Company

Joel Dembowski

Negative

Comments
Submitted

3

Southern Indiana Gas
and Electric Co.

Ryan Snyder

Negative

Comments
Submitted

3

Tacoma Public Utilities
(Tacoma, WA)

John Nierenberg

None

N/A

3

Tennessee Valley
Authority

Ian Grant

Negative

Comments
Submitted

3

Tri-State G and T
Association, Inc.

Ryan Walter

Affirmative

N/A

3

Xcel Energy, Inc.

Nicholas Friebel

Negative

Third-Party
Comments

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Negative

Third-Party
Comments

4

Arkansas Electric
Cooperative Corporation

Jenni Sudduth

None

N/A

4

Austin Energy

Tony Hua

Affirmative

N/A

4

Buckeye Power, Inc.

Jason Procuniar

Negative

Third-Party
Comments

4

City Utilities of Springfield,
Missouri

Jerry Bradshaw

Negative

Third-Party
Comments

4

CMS Energy Consumers Energy
Company

Aric Root

Negative

Comments
Submitted

4

DTE Energy

Patricia Ireland

None

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

Negative

Comments
Submitted

4

Georgia System
Operations Corporation

Katrina Lyons

Negative

Comments
Submitted

4

North Carolina Electric
Membership Corporation

Richard McCall

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Ryan Strom

Scott Brame

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

4

Public Utility District No. 1
of Snohomish County

John D.
Martinsen

Negative

Comments
Submitted

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Abstain

N/A

4

Sacramento Municipal
Utility District

Foung Mua

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Ken Habgood

None

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

None

N/A

4

Utility Services, Inc.

Carver Powers

Affirmative

N/A

4

Western Power Pool

Kevin Conway

Negative

Comments
Submitted

5

AEP

Thomas Foltz

Affirmative

N/A

5

AES - AES Corporation

Ruchi Shah

Abstain

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Negative

Comments
Submitted

5

APS - Arizona Public
Service Co.

Andrew Smith

Negative

Comments
Submitted

5

Associated Electric
Cooperative, Inc.

Chuck Booth

Negative

Comments
Submitted

5

Austin Energy

Michael Dillard

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

Negative

Comments
Submitted

5

BC Hydro and Power
Authority

Quincy Wang

Negative

Comments
Submitted

5

Berkshire Hathaway - NV
Energy

Dwanique Spiller

Negative

Comments
Submitted

5

Black Hills Corporation

Sheila Suurmeier

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Tim Kelley

Jennie Wike

Segment

Organization

Voter

5

Bonneville Power
Administration

Juergen Bermejo

5

Buckeye Power, Inc.

Kevin Zemanek

5

California Department of
Water Resources

5

Designated
Proxy

Ballot

NERC
Memo

Negative

Comments
Submitted

Negative

Third-Party
Comments

ASM Mostafa

None

N/A

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

CMS Energy Consumers Energy
Company

David
Greyerbiehl

Negative

Comments
Submitted

5

Colorado Springs Utilities

Jeffrey Icke

Negative

Third-Party
Comments

5

Con Ed - Consolidated
Edison Co. of New York

Michelle Pagano

Affirmative

N/A

5

Constellation

Alison MacKellar

Abstain

N/A

5

Cowlitz County PUD

Deanna Carlson

Affirmative

N/A

5

Dairyland Power
Cooperative

Tommy Drea

Negative

Third-Party
Comments

5

Dominion - Dominion
Resources, Inc.

Anna Salmon

Negative

Comments
Submitted

5

DTE Energy - Detroit
Edison Company

Mohamad
Elhusseini

Abstain

N/A

5

Duke Energy

Dale Goodwine

Negative

Comments
Submitted

5

Edison International Southern California
Edison Company

Selene Willis

Negative

Comments
Submitted

5

Entergy - Entergy
Services, Inc.

Gail Golden

Negative

Comments
Submitted

5

Evergy

Jeremy Harris

Negative

Comments
Submitted

Negative

Comments
Submitted

5

FirstEnergy - FirstEnergy
Matthew
Corporation
Augustin
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB01

Ryan Strom

Hayden Maples

Segment

Organization

Voter

5

Florida Municipal Power
Agency

Chris Gowder

5

Great River Energy

5

Designated
Proxy

NERC
Memo

Abstain

N/A

Jacalynn Bentz

None

N/A

Greybeard Compliance
Services, LLC

Mike Gabriel

Abstain

N/A

5

Grid Strategies LLC

Michael Goggin

Negative

Comments
Submitted

5

Hydro-Quebec (HQ)

Junji Yamaguchi

Negative

Comments
Submitted

5

Imperial Irrigation District

Tino Zaragoza

Affirmative

N/A

5

Invenergy LLC

Rhonda Jones

None

N/A

5

JEA

John Babik

Negative

Comments
Submitted

5

Lincoln Electric System

Brittany Millard

Negative

Comments
Submitted

5

Los Angeles Department
of Water and Power

Glenn Barry

Abstain

N/A

5

Lower Colorado River
Authority

Teresa Krabe

Affirmative

N/A

5

LS Power Development,
LLC

C. A. Campbell

None

N/A

5

Manitoba Hydro

Kristy-Lee Young

Negative

Comments
Submitted

5

Muscatine Power and
Water

Neal Nelson

Negative

Third-Party
Comments

5

National Grid USA

Robin Berry

None

N/A

5

NB Power Corporation New Brunswick Power
Transmission Corporation

Fon Hiew

Negative

Comments
Submitted

5

Nebraska Public Power
District

Ronald Bender

Negative

Third-Party
Comments

5

New York Power Authority

Zahid Qayyum

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

LaKenya
Vannorman

Ballot

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

NextEra Energy

Richard Vendetti

Negative

Comments
Submitted

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Negative

Comments
Submitted

5

North Carolina Electric
Membership Corporation

Reid Cashion

Negative

Third-Party
Comments

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Negative

Third-Party
Comments

5

Oglethorpe Power
Corporation

Donna Johnson

Negative

Third-Party
Comments

5

Omaha Public Power
District

Kayleigh
Wilkerson

Negative

Third-Party
Comments

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Negative

Comments
Submitted

5

Orlando Utilities
Commission

Dania Colon

Affirmative

N/A

5

OTP - Otter Tail Power
Company

Stacy Wahlund

Negative

Third-Party
Comments

5

Pacific Gas and Electric
Company

Tyler Brun

Negative

Comments
Submitted

5

Pattern Operators LP

George E Brown

Negative

Third-Party
Comments

5

Platte River Power
Authority

Jon Osell

Negative

Third-Party
Comments

5

Portland General Electric
Co.

Ryan Olson

Abstain

N/A

5

PSEG Nuclear LLC

Tim Kucey

Negative

Third-Party
Comments

5

Public Utility District No. 1
of Chelan County

Rebecca Zahler

Negative

Comments
Submitted

5

Public Utility District No. 1
of Snohomish County

Becky Burden

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Scott Brame

Bob Cardle

Segment

Organization

Voter

5

Public Utility District No. 2
of Grant County,
Washington

Nikkee Hebdon

5

Sacramento Municipal
Utility District

Ryder Couch

5

Salt River Project

Thomas Johnson

5

Santee Cooper

5

Designated
Proxy

Ballot

NERC
Memo

None

N/A

Tim Kelley

Affirmative

N/A

Israel Perez

Negative

Comments
Submitted

Carey Salisbury

Negative

Comments
Submitted

Seminole Electric
Cooperative, Inc.

Melanie Wong

None

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Negative

Third-Party
Comments

5

Southern Company Southern Company
Generation

Leslie Burke

Negative

Comments
Submitted

5

Southern Indiana Gas
and Electric Co.

Larry Rogers

Negative

Comments
Submitted

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

None

N/A

5

Talen Generation, LLC

Donald Lock

None

N/A

5

Tallahassee Electric (City
of Tallahassee, FL)

Karen Weaver

Abstain

N/A

5

Tennessee Valley
Authority

Darren Boehm

Negative

Comments
Submitted

5

Tri-State G and T
Association, Inc.

Sergio Banuelos

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Kalidass

Abstain

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Negative

Third-Party
Comments

6

AEP

Mathew Miller

Affirmative

N/A

Negative

Comments
Submitted

6

Ameren - Ameren
Robert Quinlivan
Services
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

APS - Arizona Public
Service Co.

Marcus Bortman

Negative

Comments
Submitted

6

Associated Electric
Cooperative, Inc.

Brian Ackermann

Negative

Comments
Submitted

6

Austin Energy

Imane Mrini

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Lindsay Wickizer

None

N/A

6

Black Hills Corporation

Rachel Schuldt

Negative

Comments
Submitted

6

Bonneville Power
Administration

Tanner Brier

Negative

Comments
Submitted

6

Cleco Corporation

Robert Hirchak

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Jason Chandler

Affirmative

N/A

6

Constellation

Kimberly Turco

Abstain

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Negative

Comments
Submitted

6

Duke Energy

John Sturgeon

Negative

Comments
Submitted

6

Edison International Southern California
Edison Company

Stephanie Kenny

Negative

Comments
Submitted

6

Entergy

Julie Hall

Negative

Comments
Submitted

6

Evergy

Tiffany Lake

Negative

Comments
Submitted

6

FirstEnergy - FirstEnergy
Corporation

Stacey Sheehan

Negative

Comments
Submitted

6

Great River Energy

Brian Meloy

Negative

Third-Party
Comments

6

Imperial Irrigation District

Diana Torres

Affirmative

N/A

6

Lakeland Electric

Paul Shipps

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Lincoln Electric System

Eric Ruskamp

Negative

Comments
Submitted

6

Los Angeles Department
of Water and Power

Anton Vu

Abstain

N/A

6

Manitoba Hydro

Kelly Bertholet

Negative

Comments
Submitted

6

Muscatine Power and
Water

Nicholas Burns

Negative

Third-Party
Comments

6

New York Power Authority

Shelly Dineen

Negative

Third-Party
Comments

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

Negative

Comments
Submitted

6

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Negative

Comments
Submitted

6

Northern California Power
Agency

Dennis Sismaet

Negative

Comments
Submitted

6

NRG - NRG Energy, Inc.

Martin Sidor

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Ashley F Stringer

Negative

Third-Party
Comments

6

Omaha Public Power
District

Shonda McCain

Negative

Third-Party
Comments

6

Platte River Power
Authority

Sabrina Martz

Negative

Third-Party
Comments

6

Portland General Electric
Co.

Stefanie Burke

Abstain

N/A

6

Powerex Corporation

Raj Hundal

Negative

Third-Party
Comments

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Laura Wu

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Segment

Organization

Voter

6

Public Utility District No. 1
of Chelan County

Tamarra Hardie

6

Sacramento Municipal
Utility District

Charles Norton

6

Salt River Project

Timothy Singh

6

Santee Cooper

6

Designated
Proxy

Ballot

NERC
Memo

Negative

Comments
Submitted

Tim Kelley

Affirmative

N/A

Israel Perez

Negative

Comments
Submitted

Marty Watson

Negative

Comments
Submitted

Seminole Electric
Cooperative, Inc.

Bret Galbraith

None

N/A

6

Snohomish County PUD
No. 1

John Liang

None

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Negative

Comments
Submitted

6

Southern Indiana Gas
and Electric Co.

Kati Barr

Negative

Comments
Submitted

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

None

N/A

6

Western Area Power
Administration

Jennifer Neville

Negative

Comments
Submitted

6

Xcel Energy, Inc.

Steve Szablya

Negative

Third-Party
Comments

8

Florida Reliability
Coordinating Council –
Member Services Division

Vince Ordax

Abstain

N/A

10

Midwest Reliability
Organization

Mark Flanary

Affirmative

N/A

10

New York State Reliability
Council

Wesley Yeomans

Affirmative

N/A

10

Northeast Power
Coordinating Council

Gerry Dunbar

Abstain

N/A

10

ReliabilityFirst

Tyler
Schwendiman

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Negative

Comments
Submitted

10

Western Electricity
Coordinating Council

Steven Rueckert

Negative

Comments
Submitted

Previous
Showing 1 to 314 of 314 entries

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BALLOT RESULTS  
Comment: View Comment Results (/CommentResults/Index/319)
Ballot Name: 2023-07 Transmission Planning Performance Requirements for Extreme Weather Implementation Plan IN 1 OT
Voting Start Date: 4/24/2024 12:01:00 AM
Voting End Date: 5/3/2024 8:00:00 PM
Ballot Type: OT
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 276
Total Ballot Pool: 314
Quorum: 87.9
Quorum Established Date: 5/3/2024 2:21:51 PM
Weighted Segment Value: 30.03
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

89

1

20

0.274

53

0.726

0

5

11

Segment:
2

8

0.5

1

0.1

4

0.4

0

1

2

Segment:
3

68

1

13

0.217

47

0.783

0

3

5

Segment:
4

18

1

4

0.308

9

0.692

0

1

4

Segment:
5

76

1

15

0.263

42

0.737

0

9

10

Segment:
6

47

1

10

0.27

27

0.73

0

4

6

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

1

0

0

0

0

0

0

1

0

Segment

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

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:
9

0

0

0

0

0

0

0

0

0

Segment:
10

7

0.6

4

0.4

2

0.2

0

1

0

Totals:

314

6.1

67

1.832

184

4.268

0

25

38

Segment

BALLOT POOL MEMBERS
Show

All

Segment

entries

Organization

Search:

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power,
Inc.

Hillary Creurer

Negative

Comments
Submitted

1

Ameren - Ameren
Services

Tamara Evey

Affirmative

N/A

1

American Transmission
Company, LLC

Amy Wilke

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Daniela
Atanasovski

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Jennifer Bray

None

N/A

1

Associated Electric
Cooperative, Inc.

Mark Riley

Negative

Comments
Submitted

1

Austin Energy

Thomas
Standifur

Affirmative

N/A

Negative

Comments
Submitted

1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Corporation

Segment

Organization

Voter

1

Balancing Authority of
Northern California

Kevin Smith

1

BC Hydro and Power
Authority

1

Designated
Proxy

NERC
Memo

Affirmative

N/A

Adrian Andreoiu

Negative

Comments
Submitted

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

Negative

Comments
Submitted

1

Black Hills Corporation

Micah Runner

Negative

Comments
Submitted

1

Bonneville Power
Administration

Kamala RogersHolliday

Negative

Comments
Submitted

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Negative

Comments
Submitted

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

None

N/A

1

Central Iowa Power
Cooperative

Kevin Lyons

Negative

Third-Party
Comments

1

City Utilities of Springfield,
Missouri

Michael Bowman

Negative

Third-Party
Comments

1

Colorado Springs Utilities

Corey Walker

Negative

Third-Party
Comments

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dairyland Power
Cooperative

Karrie Schuldt

Negative

Third-Party
Comments

1

Dominion - Dominion
Virginia Power

Elizabeth Weber

Negative

Comments
Submitted

1

Duke Energy

Katherine Street

Affirmative

N/A

1

Edison International Southern California
Edison Company

Robert Blackney

None

N/A

1

Entergy

Brian Lindsey

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Tim Kelley

Ballot

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

Hayden Maples

Negative

Comments
Submitted

1

Evergy

Kevin Frick

1

Eversource Energy

Joshua London

Negative

Comments
Submitted

1

Exelon

Daniel Gacek

Negative

Comments
Submitted

1

FirstEnergy - FirstEnergy
Corporation

Theresa Ciancio

Negative

Comments
Submitted

1

Georgia Transmission
Corporation

Greg Davis

Affirmative

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Negative

Third-Party
Comments

1

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Emma Halilovic

Lidija Efremova

Affirmative

N/A

1

Hydro-Quebec (HQ)

Nicolas Turcotte

Chantal Mazza

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Sean Steffensen

None

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Denise Sanchez

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Allie Gavin

Negative

Comments
Submitted

1

JEA

Joseph McClung

Negative

Comments
Submitted

1

KAMO Electric
Cooperative

Micah Breedlove

Negative

Third-Party
Comments

1

Lakeland Electric

Larry Watt

Negative

Third-Party
Comments

1

Lincoln Electric System

Josh Johnson

None

N/A

1

Long Island Power
Authority

Isidoro Behar

Negative

Comments
Submitted

Abstain

N/A

1

Los Angeles Department
faranak sarbaz
of Water and Power
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Stephen
Stafford

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Lower Colorado River
Authority

Matt Lewis

Affirmative

N/A

1

LS Power Transmission,
LLC

Jennifer
Richardson

None

N/A

1

M and A Electric Power
Cooperative

William Price

Negative

Third-Party
Comments

1

Manitoba Hydro

Nazra Gladu

Negative

Comments
Submitted

1

MEAG Power

David Weekley

Rebika Yitna

Negative

Comments
Submitted

1

Minnkota Power
Cooperative Inc.

Theresa Allard

Andy Fuhrman

Negative

Comments
Submitted

1

Muscatine Power and
Water

Andrew Kurriger

Negative

Third-Party
Comments

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Negative

Third-Party
Comments

1

National Grid USA

Michael Jones

Negative

Third-Party
Comments

1

NB Power Corporation

Jeffrey Streifling

Negative

Comments
Submitted

1

Nebraska Public Power
District

Jamison Cawley

Negative

Third-Party
Comments

1

New York Power Authority

Daniel Valle

Negative

Third-Party
Comments

1

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Negative

Comments
Submitted

1

NiSource - Northern
Indiana Public Service
Co.

Alison Nickells

Negative

Comments
Submitted

1

Northeast Missouri
Electric Power
Cooperative

Brett Douglas

Negative

Third-Party
Comments

Negative

Third-Party
Comments

1

OGE Energy - Oklahoma
Terri Pyle
Gas and Electric Co.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Segment

Organization

Voter

1

Omaha Public Power
District

Doug Peterchuck

1

Oncor Electric Delivery

Byron Booker

1

Orlando Utilities
Commission

1

Designated
Proxy

Ballot

NERC
Memo

Negative

Third-Party
Comments

Negative

Comments
Submitted

Aaron Staley

Affirmative

N/A

OTP - Otter Tail Power
Company

Charles Wicklund

Negative

Third-Party
Comments

1

Pacific Gas and Electric
Company

Marco Rios

Negative

Comments
Submitted

1

Platte River Power
Authority

Marissa Archie

Negative

Third-Party
Comments

1

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Affirmative

N/A

1

Portland General Electric
Co.

Brooke Jockin

Abstain

N/A

1

PPL Electric Utilities
Corporation

Michelle
McCartney
Longo

Negative

Comments
Submitted

1

PSEG - Public Service
Electric and Gas Co.

Karen Arnold

Abstain

N/A

1

Public Utility District No. 1
of Chelan County

Diane E Landry

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Alyssia Rhoads

Negative

Comments
Submitted

1

Public Utility District No. 2
of Grant County,
Washington

Joanne Anderson

None

N/A

1

Sacramento Municipal
Utility District

Wei Shao

Tim Kelley

Affirmative

N/A

1

Salt River Project

Matthew
Jaramilla

Israel Perez

Negative

Comments
Submitted

Negative

Comments
Submitted

1
Santee Cooper
Chris Wagner
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Broc Bruton

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

SaskPower

Wayne
Guttormson

Negative

Comments
Submitted

1

Seminole Electric
Cooperative, Inc.

Kristine Ward

None

N/A

1

Sempra - San Diego Gas
and Electric

Mohamed
Derbas

Negative

Third-Party
Comments

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Negative

Third-Party
Comments

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

None

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

None

N/A

1

Tennessee Valley
Authority

David Plumb

Affirmative

N/A

1

Tri-State G and T
Association, Inc.

Donna Wood

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Abstain

N/A

1

Unisource - Tucson
Electric Power Co.

Sam Rugel

Negative

Comments
Submitted

1

VELCO -Vermont Electric
Power Company, Inc.

Randall Buswell

Abstain

N/A

1

Western Area Power
Administration

Ben Hammer

Negative

Comments
Submitted

1

Xcel Energy, Inc.

Eric Barry

Negative

Third-Party
Comments

2

California ISO

Darcy O'Connell

Abstain

N/A

2

Electric Reliability Council
of Texas, Inc.

Kennedy Meier

Affirmative

N/A

None

N/A

2

Independent Electricity
Helen Lainis
System
Operator
© 2024 - NERC Ver 4.2.1.0
Machine
Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

2

ISO New England, Inc.

John Pearson

Keith Jonassen

Negative

Comments
Submitted

2

Midcontinent ISO, Inc.

Bobbi Welch

Adrian Harris

None

N/A

2

New York Independent
System Operator

Gregory Campoli

Negative

Third-Party
Comments

2

PJM Interconnection,
L.L.C.

Thomas Foster

Negative

Third-Party
Comments

2

Southwest Power Pool,
Inc. (RTO)

Joshua Phillips

Negative

Comments
Submitted

3

AEP

Leshel Hutchings

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras Sr

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Jessica Lopez

Affirmative

N/A

3

Arkansas Electric
Cooperative Corporation

Ayslynn Mcavoy

None

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Negative

Comments
Submitted

3

Austin Energy

Lovita Griffin

Affirmative

N/A

3

Avista - Avista
Corporation

Robert Follini

Negative

Comments
Submitted

3

BC Hydro and Power
Authority

Ming Jiang

Negative

Comments
Submitted

3

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Joseph Amato

Negative

Comments
Submitted

3

Black Hills Corporation

Josh Combs

Negative

Comments
Submitted

3

Bonneville Power
Administration

Ron Sporseen

Negative

Comments
Submitted

3

Buckeye Power, Inc.

Tom Schmidt

Negative

Third-Party
Comments

Negative

Third-Party
Comments

3
Central Electric Power
Adam Weber
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Cooperative (Missouri)

Elizabeth Davis

Carly Miller

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

City Utilities of Springfield,
Missouri

Jessica
Morrissey

Negative

Third-Party
Comments

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Negative

Comments
Submitted

3

Colorado Springs Utilities

Hillary Dobson

Negative

Third-Party
Comments

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Virginia Power

Bill Garvey

Negative

Comments
Submitted

3

DTE Energy - Detroit
Edison Company

Marvin Johnson

Abstain

N/A

3

Duke Energy - Florida
Power Corporation

Marcelo
Pesantez

Affirmative

N/A

3

Edison International Southern California
Edison Company

Romel Aquino

Negative

Comments
Submitted

3

Entergy

James Keele

Negative

Comments
Submitted

3

Evergy

Marcus Moor

Negative

Comments
Submitted

3

Eversource Energy

Vicki O'Leary

Negative

Comments
Submitted

3

Exelon

Kinte Whitehead

Negative

Comments
Submitted

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Negative

Comments
Submitted

3

Georgia System
Operations Corporation

Scott McGough

None

N/A

3

Great River Energy

Michael
Brytowski

Negative

Third-Party
Comments

3

Imperial Irrigation District

George Kirschner

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

JEA

Marilyn Williams

Negative

Comments
Submitted

3

Lakeland Electric

Steven Marshall

Negative

Comments
Submitted

3

Lincoln Electric System

Sam Christensen

Negative

Comments
Submitted

3

Los Angeles Department
of Water and Power

Fausto Serratos

Abstain

N/A

3

M and A Electric Power
Cooperative

Gary Dollins

Negative

Third-Party
Comments

3

Manitoba Hydro

Mike Smith

Negative

Comments
Submitted

3

MEAG Power

Roger Brand

Negative

Comments
Submitted

3

MGE Energy - Madison
Gas and Electric Co.

Benjamin Widder

Negative

Third-Party
Comments

3

Muscatine Power and
Water

Seth Shoemaker

Negative

Third-Party
Comments

3

National Grid USA

Brian Shanahan

Negative

Third-Party
Comments

3

Nebraska Public Power
District

Tony Eddleman

Negative

Third-Party
Comments

3

New York Power Authority

David Rivera

Negative

Third-Party
Comments

3

NextEra Energy - Florida
Power and Light Co.

Karen Demos

Negative

Comments
Submitted

3

NiSource - Northern
Indiana Public Service
Co.

Steven
Taddeucci

Negative

Comments
Submitted

3

Northern California Power
Agency

Michael Whitney

Negative

Comments
Submitted

3

NW Electric Power
Cooperative, Inc.

Heath Henry

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Rebika Yitna

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Negative

Third-Party
Comments

3

Omaha Public Power
District

David Heins

Negative

Third-Party
Comments

3

OTP - Otter Tail Power
Company

Wendi Olson

Negative

Third-Party
Comments

3

Pacific Gas and Electric
Company

Sandra Ellis

Negative

Comments
Submitted

3

Platte River Power
Authority

Richard Kiess

Negative

Third-Party
Comments

3

PNM Resources - Public
Service Company of New
Mexico

Amy
Wesselkamper

Affirmative

N/A

3

Portland General Electric
Co.

Mayra Franco

Abstain

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

Christopher
Murphy

Negative

Third-Party
Comments

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Tim Kelley

Affirmative

N/A

3

Salt River Project

Mathew Weber

Israel Perez

Negative

Comments
Submitted

3

Santee Cooper

Vicky Budreau

Negative

Comments
Submitted

3

Seminole Electric
Cooperative, Inc.

Marc Sedor

None

N/A

3

Sempra - San Diego Gas
and Electric

Bryan Bennett

Negative

Third-Party
Comments

3

Sho-Me Power Electric
Cooperative

Jarrod Murdaugh

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Snohomish County PUD
No. 1

Holly Chaney

Negative

Comments
Submitted

3

Southern Company Alabama Power Company

Joel Dembowski

Affirmative

N/A

3

Southern Indiana Gas
and Electric Co.

Ryan Snyder

Negative

Comments
Submitted

3

Tacoma Public Utilities
(Tacoma, WA)

John Nierenberg

None

N/A

3

Tennessee Valley
Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T
Association, Inc.

Ryan Walter

Affirmative

N/A

3

Xcel Energy, Inc.

Nicholas Friebel

Negative

Third-Party
Comments

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Negative

Third-Party
Comments

4

Arkansas Electric
Cooperative Corporation

Jenni Sudduth

None

N/A

4

Austin Energy

Tony Hua

Affirmative

N/A

4

Buckeye Power, Inc.

Jason Procuniar

Negative

Third-Party
Comments

4

City Utilities of Springfield,
Missouri

Jerry Bradshaw

Negative

Third-Party
Comments

4

CMS Energy Consumers Energy
Company

Aric Root

Negative

Comments
Submitted

4

DTE Energy

Patricia Ireland

None

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

Negative

Comments
Submitted

4

Georgia System
Operations Corporation

Katrina Lyons

Affirmative

N/A

4

North Carolina Electric
Membership Corporation

Richard McCall

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Ryan Strom

Scott Brame

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

4

Public Utility District No. 1
of Snohomish County

John D.
Martinsen

Negative

Comments
Submitted

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Abstain

N/A

4

Sacramento Municipal
Utility District

Foung Mua

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Ken Habgood

None

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

None

N/A

4

Utility Services, Inc.

Carver Powers

Affirmative

N/A

4

Western Power Pool

Kevin Conway

Negative

Comments
Submitted

5

AEP

Thomas Foltz

Affirmative

N/A

5

AES - AES Corporation

Ruchi Shah

Abstain

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Affirmative

N/A

5

APS - Arizona Public
Service Co.

Andrew Smith

Affirmative

N/A

5

Associated Electric
Cooperative, Inc.

Chuck Booth

Negative

Comments
Submitted

5

Austin Energy

Michael Dillard

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

Negative

Comments
Submitted

5

BC Hydro and Power
Authority

Quincy Wang

Negative

Comments
Submitted

5

Berkshire Hathaway - NV
Energy

Dwanique Spiller

Negative

Comments
Submitted

5

Black Hills Corporation

Sheila Suurmeier

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Tim Kelley

Jennie Wike

Segment

Organization

Voter

5

Bonneville Power
Administration

Juergen Bermejo

5

Buckeye Power, Inc.

Kevin Zemanek

5

California Department of
Water Resources

5

Designated
Proxy

Ballot

NERC
Memo

Negative

Comments
Submitted

Negative

Third-Party
Comments

ASM Mostafa

None

N/A

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

CMS Energy Consumers Energy
Company

David
Greyerbiehl

Negative

Comments
Submitted

5

Colorado Springs Utilities

Jeffrey Icke

Negative

Third-Party
Comments

5

Con Ed - Consolidated
Edison Co. of New York

Michelle Pagano

Affirmative

N/A

5

Constellation

Alison MacKellar

Abstain

N/A

5

Cowlitz County PUD

Deanna Carlson

Affirmative

N/A

5

Dairyland Power
Cooperative

Tommy Drea

Negative

Third-Party
Comments

5

Dominion - Dominion
Resources, Inc.

Anna Salmon

Negative

Comments
Submitted

5

DTE Energy - Detroit
Edison Company

Mohamad
Elhusseini

Abstain

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Selene Willis

Negative

Comments
Submitted

5

Entergy - Entergy
Services, Inc.

Gail Golden

Negative

Comments
Submitted

5

Evergy

Jeremy Harris

Negative

Comments
Submitted

5

FirstEnergy - FirstEnergy
Corporation

Matthew
Augustin

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Ryan Strom

Hayden Maples

Segment

Organization

Voter

5

Florida Municipal Power
Agency

Chris Gowder

5

Great River Energy

5

Designated
Proxy

NERC
Memo

Abstain

N/A

Jacalynn Bentz

None

N/A

Greybeard Compliance
Services, LLC

Mike Gabriel

Abstain

N/A

5

Grid Strategies LLC

Michael Goggin

Negative

Comments
Submitted

5

Hydro-Quebec (HQ)

Junji Yamaguchi

Affirmative

N/A

5

Imperial Irrigation District

Tino Zaragoza

Affirmative

N/A

5

Invenergy LLC

Rhonda Jones

None

N/A

5

JEA

John Babik

Negative

Comments
Submitted

5

Lincoln Electric System

Brittany Millard

Negative

Comments
Submitted

5

Los Angeles Department
of Water and Power

Glenn Barry

Abstain

N/A

5

Lower Colorado River
Authority

Teresa Krabe

Affirmative

N/A

5

LS Power Development,
LLC

C. A. Campbell

None

N/A

5

Manitoba Hydro

Kristy-Lee Young

Negative

Comments
Submitted

5

Muscatine Power and
Water

Neal Nelson

Negative

Third-Party
Comments

5

National Grid USA

Robin Berry

None

N/A

5

NB Power Corporation New Brunswick Power
Transmission Corporation

Fon Hiew

Negative

Comments
Submitted

5

Nebraska Public Power
District

Ronald Bender

Negative

Third-Party
Comments

5

New York Power Authority

Zahid Qayyum

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

LaKenya
Vannorman

Ballot

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

NextEra Energy

Richard Vendetti

Negative

Comments
Submitted

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Negative

Comments
Submitted

5

North Carolina Electric
Membership Corporation

Reid Cashion

Negative

Third-Party
Comments

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Negative

Third-Party
Comments

5

Oglethorpe Power
Corporation

Donna Johnson

Negative

Third-Party
Comments

5

Omaha Public Power
District

Kayleigh
Wilkerson

Negative

Third-Party
Comments

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Negative

Comments
Submitted

5

Orlando Utilities
Commission

Dania Colon

Affirmative

N/A

5

OTP - Otter Tail Power
Company

Stacy Wahlund

Negative

Third-Party
Comments

5

Pacific Gas and Electric
Company

Tyler Brun

Negative

Comments
Submitted

5

Pattern Operators LP

George E Brown

Negative

Third-Party
Comments

5

Platte River Power
Authority

Jon Osell

Negative

Third-Party
Comments

5

Portland General Electric
Co.

Ryan Olson

Abstain

N/A

5

PSEG Nuclear LLC

Tim Kucey

Negative

Third-Party
Comments

5

Public Utility District No. 1
of Chelan County

Rebecca Zahler

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Becky Burden

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Scott Brame

Bob Cardle

Segment

Organization

Voter

5

Public Utility District No. 2
of Grant County,
Washington

Nikkee Hebdon

5

Sacramento Municipal
Utility District

Ryder Couch

5

Salt River Project

Thomas Johnson

5

Santee Cooper

5

Designated
Proxy

Ballot

NERC
Memo

None

N/A

Tim Kelley

Affirmative

N/A

Israel Perez

Negative

Comments
Submitted

Carey Salisbury

Negative

Comments
Submitted

Seminole Electric
Cooperative, Inc.

Melanie Wong

None

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Negative

Third-Party
Comments

5

Southern Company Southern Company
Generation

Leslie Burke

Affirmative

N/A

5

Southern Indiana Gas
and Electric Co.

Larry Rogers

Negative

Comments
Submitted

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

None

N/A

5

Talen Generation, LLC

Donald Lock

None

N/A

5

Tallahassee Electric (City
of Tallahassee, FL)

Karen Weaver

Abstain

N/A

5

Tennessee Valley
Authority

Darren Boehm

Negative

Comments
Submitted

5

Tri-State G and T
Association, Inc.

Sergio Banuelos

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Kalidass

Abstain

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Negative

Third-Party
Comments

6

AEP

Mathew Miller

Affirmative

N/A

Affirmative

N/A

6

Ameren - Ameren
Robert Quinlivan
Services
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

APS - Arizona Public
Service Co.

Marcus Bortman

Affirmative

N/A

6

Associated Electric
Cooperative, Inc.

Brian Ackermann

Negative

Comments
Submitted

6

Austin Energy

Imane Mrini

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Lindsay Wickizer

None

N/A

6

Black Hills Corporation

Rachel Schuldt

Negative

Comments
Submitted

6

Bonneville Power
Administration

Tanner Brier

Negative

Comments
Submitted

6

Cleco Corporation

Robert Hirchak

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Jason Chandler

Affirmative

N/A

6

Constellation

Kimberly Turco

Abstain

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Negative

Comments
Submitted

6

Duke Energy

John Sturgeon

Affirmative

N/A

6

Edison International Southern California
Edison Company

Stephanie Kenny

Negative

Comments
Submitted

6

Entergy

Julie Hall

Negative

Comments
Submitted

6

Evergy

Tiffany Lake

Negative

Comments
Submitted

6

FirstEnergy - FirstEnergy
Corporation

Stacey Sheehan

Negative

Comments
Submitted

6

Great River Energy

Brian Meloy

Negative

Third-Party
Comments

6

Imperial Irrigation District

Diana Torres

Affirmative

N/A

6

Lakeland Electric

Paul Shipps

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Lincoln Electric System

Eric Ruskamp

Negative

Comments
Submitted

6

Los Angeles Department
of Water and Power

Anton Vu

Abstain

N/A

6

Manitoba Hydro

Kelly Bertholet

Negative

Comments
Submitted

6

Muscatine Power and
Water

Nicholas Burns

Negative

Third-Party
Comments

6

New York Power Authority

Shelly Dineen

Negative

Third-Party
Comments

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

Negative

Comments
Submitted

6

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Negative

Comments
Submitted

6

Northern California Power
Agency

Dennis Sismaet

Negative

Comments
Submitted

6

NRG - NRG Energy, Inc.

Martin Sidor

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Ashley F Stringer

Negative

Third-Party
Comments

6

Omaha Public Power
District

Shonda McCain

Negative

Third-Party
Comments

6

Platte River Power
Authority

Sabrina Martz

Negative

Third-Party
Comments

6

Portland General Electric
Co.

Stefanie Burke

Abstain

N/A

6

Powerex Corporation

Raj Hundal

Negative

Third-Party
Comments

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Laura Wu

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Segment

Organization

Voter

6

Public Utility District No. 1
of Chelan County

Tamarra Hardie

6

Sacramento Municipal
Utility District

Charles Norton

6

Salt River Project

Timothy Singh

6

Santee Cooper

6

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Tim Kelley

Affirmative

N/A

Israel Perez

Negative

Comments
Submitted

Marty Watson

Negative

Comments
Submitted

Seminole Electric
Cooperative, Inc.

Bret Galbraith

None

N/A

6

Snohomish County PUD
No. 1

John Liang

None

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Southern Indiana Gas
and Electric Co.

Kati Barr

Negative

Comments
Submitted

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

None

N/A

6

Western Area Power
Administration

Jennifer Neville

Negative

Comments
Submitted

6

Xcel Energy, Inc.

Steve Szablya

Negative

Third-Party
Comments

8

Florida Reliability
Coordinating Council –
Member Services Division

Vince Ordax

Abstain

N/A

10

Midwest Reliability
Organization

Mark Flanary

Affirmative

N/A

10

New York State Reliability
Council

Wesley Yeomans

Affirmative

N/A

10

Northeast Power
Coordinating Council

Gerry Dunbar

Abstain

N/A

10

ReliabilityFirst

Tyler
Schwendiman

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Negative

Comments
Submitted

10

Western Electricity
Coordinating Council

Steven Rueckert

Negative

Comments
Submitted

Previous
Showing 1 to 314 of 314 entries

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

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NERC Balloting Tool (/)

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BALLOT RESULTS  
Ballot Name: 2023-07 Transmission Planning Performance Requirements for Extreme Weather TPL-008-1 | Non-binding Poll
IN 1 NB
Voting Start Date: 4/24/2024 12:01:00 AM
Voting End Date: 5/3/2024 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 262
Total Ballot Pool: 297
Quorum: 88.22
Quorum Established Date: 5/3/2024 2:21:59 PM
Weighted Segment Value: 16.67
Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
1

86

1

10

0.172

48

0.828

14

14

Segment:
2

7

0.5

0

0

5

0.5

1

1

Segment:
3

63

1

6

0.12

44

0.88

10

3

Segment:
4

18

1

1

0.083

11

0.917

2

4

Segment:
5

72

1

9

0.196

37

0.804

18

8

Segment:
6

44

1

5

0.172

24

0.828

10

5

Segment:
7

0

0

0

0

0

0

0

0

Segment:
8

1

0

0

0

0

0

1

0

Segment:
9

0

0

0

0

0

0

0

0

Segment

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
10

6

0.4

3

0.3

1

0.1

2

0

Totals:

297

5.9

34

1.044

170

4.856

58

35

Segment

BALLOT POOL MEMBERS
Show

All

Segment

entries

Organization

Search:

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power,
Inc.

Hillary Creurer

Negative

Comments
Submitted

1

Ameren - Ameren
Services

Tamara Evey

Abstain

N/A

1

American Transmission
Company, LLC

Amy Wilke

None

N/A

1

APS - Arizona Public
Service Co.

Daniela
Atanasovski

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Jennifer Bray

None

N/A

1

Associated Electric
Cooperative, Inc.

Mark Riley

Negative

Comments
Submitted

1

Austin Energy

Thomas
Standifur

Abstain

N/A

1

Avista - Avista
Corporation

Mike Magruder

Negative

Comments
Submitted

1

Balancing Authority of
Northern California

Kevin Smith

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Tim Kelley

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

BC Hydro and Power
Authority

Adrian Andreoiu

Negative

Comments
Submitted

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

Negative

Comments
Submitted

1

Black Hills Corporation

Micah Runner

Abstain

N/A

1

Bonneville Power
Administration

Kamala RogersHolliday

Negative

Comments
Submitted

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Negative

Comments
Submitted

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

None

N/A

1

Central Iowa Power
Cooperative

Kevin Lyons

Negative

Comments
Submitted

1

City Utilities of Springfield,
Missouri

Michael Bowman

Negative

Comments
Submitted

1

Colorado Springs Utilities

Corey Walker

Negative

Comments
Submitted

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dairyland Power
Cooperative

Karrie Schuldt

Negative

Comments
Submitted

1

Dominion - Dominion
Virginia Power

Elizabeth Weber

Negative

Comments
Submitted

1

Duke Energy

Katherine Street

Negative

Comments
Submitted

1

Edison International Southern California
Edison Company

Robert Blackney

None

N/A

1

Entergy

Brian Lindsey

Negative

Comments
Submitted

1

Evergy

Kevin Frick

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Eversource Energy

Joshua London

Negative

Comments
Submitted

1

Exelon

Daniel Gacek

Negative

Comments
Submitted

1

FirstEnergy - FirstEnergy
Corporation

Theresa Ciancio

Negative

Comments
Submitted

1

Georgia Transmission
Corporation

Greg Davis

Negative

Comments
Submitted

1

Glencoe Light and Power
Commission

Terry Volkmann

Negative

Comments
Submitted

1

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Emma Halilovic

Lidija Efremova

Affirmative

N/A

1

Hydro-Quebec (HQ)

Nicolas Turcotte

Chantal Mazza

Negative

Comments
Submitted

1

IDACORP - Idaho Power
Company

Sean Steffensen

None

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Denise Sanchez

Affirmative

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Allie Gavin

Affirmative

N/A

1

JEA

Joseph McClung

Negative

Comments
Submitted

1

KAMO Electric
Cooperative

Micah Breedlove

Negative

Comments
Submitted

1

Lakeland Electric

Larry Watt

Negative

Comments
Submitted

1

Lincoln Electric System

Josh Johnson

None

N/A

1

Long Island Power
Authority

Isidoro Behar

Abstain

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Abstain

N/A

Affirmative

N/A

1
Lower Colorado River
Matt Lewis
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Authority

Stephen
Stafford

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

LS Power Transmission,
LLC

Jennifer
Richardson

None

N/A

1

M and A Electric Power
Cooperative

William Price

Negative

Comments
Submitted

1

MEAG Power

David Weekley

Rebika Yitna

Negative

Comments
Submitted

1

Minnkota Power
Cooperative Inc.

Theresa Allard

Andy Fuhrman

Negative

Comments
Submitted

1

Muscatine Power and
Water

Andrew Kurriger

Negative

Comments
Submitted

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Negative

Comments
Submitted

1

National Grid USA

Michael Jones

Negative

Comments
Submitted

1

NB Power Corporation

Jeffrey Streifling

Abstain

N/A

1

Nebraska Public Power
District

Jamison Cawley

Abstain

N/A

1

New York Power Authority

Daniel Valle

Negative

Comments
Submitted

1

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Abstain

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Alison Nickells

Negative

Comments
Submitted

1

Northeast Missouri
Electric Power
Cooperative

Brett Douglas

Negative

Comments
Submitted

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Negative

Comments
Submitted

1

Omaha Public Power
District

Doug Peterchuck

Negative

Comments
Submitted

1

Oncor Electric Delivery

Byron Booker

Abstain

N/A

Affirmative

N/A

1

Orlando Utilities
Aaron Staley
Commission
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB01

Broc Bruton

Segment

Organization

Voter

1

Pacific Gas and Electric
Company

Marco Rios

1

Platte River Power
Authority

1

Designated
Proxy

NERC
Memo

Negative

Comments
Submitted

Marissa Archie

Negative

Comments
Submitted

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Negative

Comments
Submitted

1

Portland General Electric
Co.

Brooke Jockin

Abstain

N/A

1

PPL Electric Utilities
Corporation

Michelle
McCartney
Longo

None

N/A

1

PSEG - Public Service
Electric and Gas Co.

Karen Arnold

Negative

Comments
Submitted

1

Public Utility District No. 1
of Chelan County

Diane E Landry

Negative

Comments
Submitted

1

Public Utility District No. 1
of Snohomish County

Alyssia Rhoads

Negative

Comments
Submitted

1

Public Utility District No. 2
of Grant County,
Washington

Joanne Anderson

None

N/A

1

Sacramento Municipal
Utility District

Wei Shao

Tim Kelley

Negative

Comments
Submitted

1

Salt River Project

Matthew
Jaramilla

Israel Perez

Negative

Comments
Submitted

1

Santee Cooper

Chris Wagner

Abstain

N/A

1

SaskPower

Wayne
Guttormson

Negative

Comments
Submitted

1

Seminole Electric
Cooperative, Inc.

Kristine Ward

None

N/A

1

Sempra - San Diego Gas
and Electric

Mohamed
Derbas

Negative

Comments
Submitted

Affirmative

N/A

1

Southern Company Matt Carden
Southern Company
Services,
Inc. Name: ATLVPEROWEB01
© 2024 - NERC Ver 4.2.1.0
Machine

Bob Cardle

Ballot

Segment

Organization

Voter

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

1

Tallahassee Electric (City
of Tallahassee, FL)

1

Designated
Proxy

Ballot

NERC
Memo

Negative

Comments
Submitted

None

N/A

Scott Langston

None

N/A

Tennessee Valley
Authority

David Plumb

Abstain

N/A

1

Tri-State G and T
Association, Inc.

Donna Wood

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Abstain

N/A

1

Unisource - Tucson
Electric Power Co.

Sam Rugel

Abstain

N/A

1

VELCO -Vermont Electric
Power Company, Inc.

Randall Buswell

None

N/A

1

Western Area Power
Administration

Ben Hammer

Negative

Comments
Submitted

2

Electric Reliability Council
of Texas, Inc.

Kennedy Meier

Negative

Comments
Submitted

2

Independent Electricity
System Operator

Helen Lainis

None

N/A

2

ISO New England, Inc.

John Pearson

Keith Jonassen

Negative

Comments
Submitted

2

Midcontinent ISO, Inc.

Bobbi Welch

Adrian Harris

Negative

Comments
Submitted

2

New York Independent
System Operator

Gregory Campoli

Negative

Comments
Submitted

2

PJM Interconnection,
L.L.C.

Thomas Foster

Abstain

N/A

2

Southwest Power Pool,
Inc. (RTO)

Joshua Phillips

Negative

Comments
Submitted

3

AEP

Leshel Hutchings

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Elizabeth Davis

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Ameren - Ameren
Services

David Jendras Sr

Abstain

N/A

3

APS - Arizona Public
Service Co.

Jessica Lopez

Affirmative

N/A

3

Arkansas Electric
Cooperative Corporation

Ayslynn Mcavoy

None

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Negative

Comments
Submitted

3

Austin Energy

Lovita Griffin

Abstain

N/A

3

Avista - Avista
Corporation

Robert Follini

Negative

Comments
Submitted

3

BC Hydro and Power
Authority

Ming Jiang

Negative

Comments
Submitted

3

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Joseph Amato

Negative

Comments
Submitted

3

Black Hills Corporation

Josh Combs

Abstain

N/A

3

Bonneville Power
Administration

Ron Sporseen

Negative

Comments
Submitted

3

Buckeye Power, Inc.

Tom Schmidt

Negative

Comments
Submitted

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Negative

Comments
Submitted

3

City Utilities of Springfield,
Missouri

Jessica
Morrissey

Negative

Comments
Submitted

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

Negative

Comments
Submitted

3

Colorado Springs Utilities

Hillary Dobson

Negative

Comments
Submitted

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Virginia Power

Bill Garvey

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Carly Miller

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

DTE Energy - Detroit
Edison Company

Marvin Johnson

Abstain

N/A

3

Duke Energy - Florida
Power Corporation

Marcelo
Pesantez

Negative

Comments
Submitted

3

Edison International Southern California
Edison Company

Romel Aquino

Negative

Comments
Submitted

3

Entergy

James Keele

Negative

Comments
Submitted

3

Evergy

Marcus Moor

Negative

Comments
Submitted

3

Eversource Energy

Vicki O'Leary

Negative

Comments
Submitted

3

Exelon

Kinte Whitehead

Negative

Comments
Submitted

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Negative

Comments
Submitted

3

Great River Energy

Michael
Brytowski

Negative

Comments
Submitted

3

Imperial Irrigation District

George Kirschner

Affirmative

N/A

3

JEA

Marilyn Williams

Negative

Comments
Submitted

3

Lakeland Electric

Steven Marshall

Negative

Comments
Submitted

3

Lincoln Electric System

Sam Christensen

Abstain

N/A

3

M and A Electric Power
Cooperative

Gary Dollins

Negative

Comments
Submitted

3

MEAG Power

Roger Brand

Negative

Comments
Submitted

3

MGE Energy - Madison
Gas and Electric Co.

Benjamin Widder

Negative

Comments
Submitted

3

Muscatine Power and
Water

Seth Shoemaker

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Denise Sanchez

Rebika Yitna

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

National Grid USA

Brian Shanahan

Negative

Comments
Submitted

3

Nebraska Public Power
District

Tony Eddleman

Abstain

N/A

3

New York Power Authority

David Rivera

Negative

Comments
Submitted

3

NextEra Energy - Florida
Power and Light Co.

Karen Demos

Negative

Comments
Submitted

3

NiSource - Northern
Indiana Public Service
Co.

Steven
Taddeucci

Negative

Comments
Submitted

3

Northern California Power
Agency

Michael Whitney

Negative

Comments
Submitted

3

NW Electric Power
Cooperative, Inc.

Heath Henry

Negative

Comments
Submitted

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Negative

Comments
Submitted

3

Omaha Public Power
District

David Heins

Negative

Comments
Submitted

3

Pacific Gas and Electric
Company

Sandra Ellis

Negative

Comments
Submitted

3

Platte River Power
Authority

Richard Kiess

Negative

Comments
Submitted

3

PNM Resources - Public
Service Company of New
Mexico

Amy
Wesselkamper

Negative

Comments
Submitted

3

Portland General Electric
Co.

Mayra Franco

Abstain

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

Christopher
Murphy

Abstain

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Sacramento Municipal
Utility District

Nicole Looney

Tim Kelley

Negative

Comments
Submitted

3

Salt River Project

Mathew Weber

Israel Perez

Negative

Comments
Submitted

3

Santee Cooper

Vicky Budreau

Abstain

N/A

3

Seminole Electric
Cooperative, Inc.

Marc Sedor

None

N/A

3

Sempra - San Diego Gas
and Electric

Bryan Bennett

Negative

Comments
Submitted

3

Sho-Me Power Electric
Cooperative

Jarrod Murdaugh

Negative

Comments
Submitted

3

Snohomish County PUD
No. 1

Holly Chaney

Negative

Comments
Submitted

3

Southern Company Alabama Power Company

Joel Dembowski

Affirmative

N/A

3

Southern Indiana Gas and
Electric Co.

Ryan Snyder

Negative

Comments
Submitted

3

Tacoma Public Utilities
(Tacoma, WA)

John Nierenberg

Negative

Comments
Submitted

3

Tennessee Valley
Authority

Ian Grant

Abstain

N/A

3

Tri-State G and T
Association, Inc.

Ryan Walter

Affirmative

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Negative

Comments
Submitted

4

Arkansas Electric
Cooperative Corporation

Jenni Sudduth

None

N/A

4

Austin Energy

Tony Hua

Abstain

N/A

4

Buckeye Power, Inc.

Jason Procuniar

Negative

Comments
Submitted

4

City Utilities of Springfield,
Missouri

Jerry Bradshaw

Negative

Comments
Submitted

Negative

Comments
Submitted

4 - NERC Ver 4.2.1.0
CMS Energy
- Consumers
Aric Root
© 2024
Machine
Name: ATLVPEROWEB01
Energy Company

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

DTE Energy

Patricia Ireland

None

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

Negative

Comments
Submitted

4

Georgia System
Operations Corporation

Katrina Lyons

Negative

Comments
Submitted

4

North Carolina Electric
Membership Corporation

Richard McCall

Negative

Comments
Submitted

4

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

4

Public Utility District No. 1
of Snohomish County

John D.
Martinsen

Negative

Comments
Submitted

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Abstain

N/A

4

Sacramento Municipal
Utility District

Foung Mua

Negative

Comments
Submitted

4

Seminole Electric
Cooperative, Inc.

Ken Habgood

None

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

None

N/A

4

Utility Services, Inc.

Carver Powers

Affirmative

N/A

4

Western Power Pool

Kevin Conway

Negative

Comments
Submitted

5

AEP

Thomas Foltz

Affirmative

N/A

5

AES - AES Corporation

Ruchi Shah

Abstain

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Abstain

N/A

5

APS - Arizona Public
Service Co.

Andrew Smith

Affirmative

N/A

5

Associated Electric
Cooperative, Inc.

Chuck Booth

Negative

Comments
Submitted

5

Austin Energy

Michael Dillard

Abstain

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Scott Brame

Tim Kelley

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Avista - Avista
Corporation

Glen Farmer

Negative

Comments
Submitted

5

BC Hydro and Power
Authority

Quincy Wang

Negative

Comments
Submitted

5

Berkshire Hathaway - NV
Energy

Dwanique Spiller

Negative

Comments
Submitted

5

Black Hills Corporation

Sheila Suurmeier

Abstain

N/A

5

Bonneville Power
Administration

Juergen Bermejo

Negative

Comments
Submitted

5

Buckeye Power, Inc.

Kevin Zemanek

Negative

Comments
Submitted

5

California Department of
Water Resources

ASM Mostafa

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

Negative

Comments
Submitted

5

Colorado Springs Utilities

Jeffrey Icke

Negative

Comments
Submitted

5

Con Ed - Consolidated
Edison Co. of New York

Michelle Pagano

Affirmative

N/A

5

Constellation

Alison MacKellar

Abstain

N/A

5

Cowlitz County PUD

Deanna Carlson

Affirmative

N/A

5

Dairyland Power
Cooperative

Tommy Drea

Negative

Comments
Submitted

5

Dominion - Dominion
Resources, Inc.

Anna Salmon

Negative

Comments
Submitted

5

DTE Energy - Detroit
Edison Company

Mohamad
Elhusseini

Abstain

N/A

5

Duke Energy

Dale Goodwine

Negative

Comments
Submitted

Negative

Comments
Submitted

5

Edison International Selene Willis
Southern California
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Edison Company

Ryan Strom

Segment

Organization

Voter

5

Entergy - Entergy
Services, Inc.

Gail Golden

5

Evergy

Jeremy Harris

5

FirstEnergy - FirstEnergy
Corporation

Matthew
Augustin

5

Florida Municipal Power
Agency

Chris Gowder

5

Greybeard Compliance
Services, LLC

5

Designated
Proxy

Ballot

NERC
Memo

Negative

Comments
Submitted

Negative

Comments
Submitted

Negative

Comments
Submitted

Abstain

N/A

Mike Gabriel

Abstain

N/A

Grid Strategies LLC

Michael Goggin

Negative

Comments
Submitted

5

Hydro-Quebec (HQ)

Junji Yamaguchi

Negative

Comments
Submitted

5

Imperial Irrigation District

Tino Zaragoza

Affirmative

N/A

5

JEA

John Babik

Negative

Comments
Submitted

5

Lincoln Electric System

Brittany Millard

Abstain

N/A

5

Los Angeles Department
of Water and Power

Glenn Barry

Abstain

N/A

5

Lower Colorado River
Authority

Teresa Krabe

Affirmative

N/A

5

LS Power Development,
LLC

C. A. Campbell

None

N/A

5

Muscatine Power and
Water

Neal Nelson

Negative

Comments
Submitted

5

National Grid USA

Robin Berry

None

N/A

5

NB Power Corporation New Brunswick Power
Transmission Corporation

Fon Hiew

Abstain

N/A

5

Nebraska Public Power
District

Ronald Bender

Abstain

N/A

Negative

Comments
Submitted

5
New York Power Authority
Zahid Qayyum
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

LaKenya
Vannorman

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

NextEra Energy

Richard Vendetti

Negative

Comments
Submitted

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Negative

Comments
Submitted

5

North Carolina Electric
Membership Corporation

Reid Cashion

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Negative

Comments
Submitted

5

Oglethorpe Power
Corporation

Donna Johnson

Negative

Comments
Submitted

5

Omaha Public Power
District

Kayleigh
Wilkerson

Negative

Comments
Submitted

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Negative

Comments
Submitted

5

Orlando Utilities
Commission

Dania Colon

Affirmative

N/A

5

OTP - Otter Tail Power
Company

Stacy Wahlund

Negative

Comments
Submitted

5

Pacific Gas and Electric
Company

Tyler Brun

Negative

Comments
Submitted

5

Pattern Operators LP

George E Brown

Negative

Comments
Submitted

5

Platte River Power
Authority

Jon Osell

Negative

Comments
Submitted

5

Portland General Electric
Co.

Ryan Olson

Abstain

N/A

5

PSEG Nuclear LLC

Tim Kucey

Abstain

N/A

5

Public Utility District No. 1
of Chelan County

Rebecca Zahler

Negative

Comments
Submitted

5

Public Utility District No. 1
of Snohomish County

Becky Burden

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Scott Brame

Bob Cardle

Segment

Organization

Voter

5

Public Utility District No. 2
of Grant County,
Washington

Nikkee Hebdon

5

Sacramento Municipal
Utility District

Ryder Couch

5

Salt River Project

Thomas Johnson

5

Santee Cooper

5

Designated
Proxy

Ballot

NERC
Memo

None

N/A

Tim Kelley

Negative

Comments
Submitted

Israel Perez

Negative

Comments
Submitted

Carey Salisbury

Abstain

N/A

Seminole Electric
Cooperative, Inc.

Melanie Wong

None

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Negative

Comments
Submitted

5

Southern Company Southern Company
Generation

Leslie Burke

Affirmative

N/A

5

Southern Indiana Gas and
Electric Co.

Larry Rogers

Negative

Comments
Submitted

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

None

N/A

5

Tallahassee Electric (City
of Tallahassee, FL)

Karen Weaver

Abstain

N/A

5

Tennessee Valley
Authority

Darren Boehm

None

N/A

5

Tri-State G and T
Association, Inc.

Sergio Banuelos

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Kalidass

Abstain

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Abstain

N/A

6

AEP

Mathew Miller

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Abstain

N/A

6

APS - Arizona Public
Service Co.

Marcus Bortman

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Associated Electric
Cooperative, Inc.

Brian Ackermann

Negative

Comments
Submitted

6

Austin Energy

Imane Mrini

Abstain

N/A

6

Berkshire Hathaway PacifiCorp

Lindsay Wickizer

None

N/A

6

Black Hills Corporation

Rachel Schuldt

Abstain

N/A

6

Bonneville Power
Administration

Tanner Brier

Negative

Comments
Submitted

6

Con Ed - Consolidated
Edison Co. of New York

Jason Chandler

Affirmative

N/A

6

Constellation

Kimberly Turco

Abstain

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Negative

Comments
Submitted

6

Duke Energy

John Sturgeon

Negative

Comments
Submitted

6

Edison International Southern California
Edison Company

Stephanie Kenny

Negative

Comments
Submitted

6

Entergy

Julie Hall

Negative

Comments
Submitted

6

Evergy

Tiffany Lake

Negative

Comments
Submitted

6

FirstEnergy - FirstEnergy
Corporation

Stacey Sheehan

Negative

Comments
Submitted

6

Great River Energy

Brian Meloy

Negative

Comments
Submitted

6

Imperial Irrigation District

Diana Torres

Affirmative

N/A

6

Lakeland Electric

Paul Shipps

Negative

Comments
Submitted

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

Abstain

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Muscatine Power and
Water

Nicholas Burns

Negative

Comments
Submitted

6

New York Power Authority

Shelly Dineen

Negative

Comments
Submitted

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

Negative

Comments
Submitted

6

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Negative

Comments
Submitted

6

Northern California Power
Agency

Dennis Sismaet

Negative

Comments
Submitted

6

NRG - NRG Energy, Inc.

Martin Sidor

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Ashley F Stringer

Negative

Comments
Submitted

6

Omaha Public Power
District

Shonda McCain

Negative

Comments
Submitted

6

Platte River Power
Authority

Sabrina Martz

Negative

Comments
Submitted

6

Portland General Electric
Co.

Stefanie Burke

Abstain

N/A

6

Powerex Corporation

Raj Hundal

Negative

Comments
Submitted

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

PSEG - PSEG Energy
Resources and Trade LLC

Laura Wu

Abstain

N/A

6

Public Utility District No. 1
of Chelan County

Tamarra Hardie

Negative

Comments
Submitted

6

Sacramento Municipal
Utility District

Charles Norton

Tim Kelley

Negative

Comments
Submitted

6

Salt River Project

Timothy Singh

Israel Perez

Negative

Comments
Submitted

6

Santee Cooper

Marty Watson

Abstain

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Seminole Electric
Cooperative, Inc.

Bret Galbraith

None

N/A

6

Snohomish County PUD
No. 1

John Liang

None

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Southern Indiana Gas and
Electric Co.

Kati Barr

Negative

Comments
Submitted

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

None

N/A

6

Western Area Power
Administration

Jennifer Neville

Negative

Comments
Submitted

8

Florida Reliability
Coordinating Council –
Member Services Division

Vince Ordax

Abstain

N/A

10

Midwest Reliability
Organization

Mark Flanary

Affirmative

N/A

10

Northeast Power
Coordinating Council

Gerry Dunbar

Abstain

N/A

10

ReliabilityFirst

Tyler
Schwendiman

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Negative

Comments
Submitted

10

Western Electricity
Coordinating Council

Steven Rueckert

Abstain

N/A

Jennie Wike

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1

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

This is the second draft of the proposed standard posted for a 38-day formal comment period
with additional ballot.
Completed Actions

Date

Standards Committee approved Standard Authorization Request (SAR)
for posting

July 19, 2023

SAR posted for comment

August 8 – September 27,
2023

45-day formal comment period with initial ballot

March 20 – May 3, 2024

Anticipated Actions

Date

38-day formal comment period with additional ballot

July 16 – August 22, 2024

45-day formal comment period with additional ballot

September 2024

10-day final ballot

November 2024

Board adoption

December 2024

Draft 2 of TPL-008-1
July 2024

Page 1 of 30

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

New or Modified Term(s) Used in NERC Reliability Standards

This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):

Extreme Temperature Assessment – Documented evaluation of future TransmissionBulk
Electric System performance for extreme heat and extreme cold temperature benchmark
events.

Draft 2 of TPL-008-1
July 2024

Page 2 of 30

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements for
Extreme Temperature Events

2.

Number:

TPL-008-1

3.

Purpose:

Establish requirements for Transmission system planning performance
forrequirements to develop a Bulk Power System (BPS) that will operate
reliably during extreme heat and extreme cold temperature events.

3.

Applicability:
3.1. Functional Entities:
4.1.1. Transmission Planner
4.1.2. Planning Coordinator

4.

Effective Date: See Implementation Plan for Project 2023-07.

Draft 2 of TPL-008-1
July 2024

Page 3 of 30

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

B. Requirements and Measures
R1. Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
determine and identify each entity’s individual and joint responsibilities for
performing the studies needed to completecompleting the Extreme Temperature
Assessment. [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
M1.Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
provide documentation of each entity’s individual and joint responsibilities, such as
meeting minutes, agreements, copies of procedures or protocols in effect between
entities or between departments of a vertically integrated system, or email
correspondence that identifies an agreement has been reached on individual and joint
responsibilities for performing the studies needed to completecompleting the Extreme
Temperature Assessment.
R2. Each responsible entity, as identified in Requirement R1, shall select at least one
extreme heat benchmark temperature event and at least one extreme cold
benchmark temperature event, from the approved benchmark library, approved and
maintained by the Electric Reliability Organization (ERO), for performingcompleting
the Extreme Temperature Assessment. [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
M2. Each responsible entity, as identified in Requirement R1, shall have evidence in either
electronic or hard copy format of its selectedselecting at least one extreme heat
benchmark event and at least one extreme cold benchmark temperature event for
performingcompleting the Extreme Temperature Assessment.
R3. Each Planning Coordinator shall develop and implement a process for coordinating the
development of benchmark planning cases among, using the selected benchmark
temperature events identified in Requirement R2, among adjacent impacted Planning
Coordinator(s), Transmission Planner(s), and other designated study entities based on
the selected benchmark events as identified in Requirement R2., within an
Interconnection. This process shall: include seasonal and temperature dependent
adjustments for Load, generation, Transmission, and transfers to represent the
selected benchmark temperature events. [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
3.1. Define the planning study area boundary based on the selected benchmark
events.
3.2. Modify the benchmark planning cases to include seasonal and temperature
dependent adjustment for Load, generation, Transmission, and transfers which
represents the selected benchmark events.
M3. Each Planning Coordinator shall providehave dated evidence ofthat it developed and
implemented a process for coordinating the development of benchmark planning
cases among impacted Planning Coordinators, and Transmission Planner(s) as
specified in Requirement R3. Acceptable evidence may include, but is not limited to,
Draft 2 of TPL-008-1
July 2024

Page 4 of 30

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

the following dated documentation (electronic or hardcopy format): records defining
the planning study area boundary based on the selected benchmark events and
modifications to the benchmark planning cases that includeincludes seasonal and
temperature dependent adjustment for Load, generation, Transmission, and transfers
whichto represent the selected benchmark temperature events.
R4.

Each responsible entity, as identified in Requirement R1, shall develop and maintain
System models within its planning area for performing the Extreme Temperature
Assessment. The System models shall use the coordination process developed in
accordance with Requirement R3 and data consistent with that provided in
accordance with the MOD-032 standard, supplemented by other sources as needed,
and shall represent projected System conditions based on the selected benchmark
events as identified in Requirement R2.to develop and maintain the following:
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. Each responsible entity,Benchmark planning cases that include seasonal and
temperature dependent adjustments for Load, generation, Transmission, and
transfers to represent the System conditions of the selected benchmark
temperature events as identified in Requirement R2 for one of the years in the
Long-Term Transmission Planning Horizon. The rationale for the year selected for
evaluation shall be available as supporting information. R1,This establishes
Category P0 as the normal System condition in Table 1.
4.2. Sensitivity cases to demonstrate the impact of changes to the basic assumptions
used in the benchmark planning cases. To accomplish this, the sensitivity cases
shall have changes to at least one of the following conditions:
•

Generation;

•

Real and reactive forecasted Load; or

•

Transfers.

M4. Each responsible entity shall have dated evidence in either electronic or hard copy
format that it developed and maintained System models of the responsible
entity’sbenchmark planning areacases and sensitivity cases for performingcompleting
the Extreme Temperature Assessment.
R5. Each responsible entity, as identified in Requirement R1, shall have criteria for
acceptable System steady state voltage limits and, post-Contingency voltage
deviations, and applicable Facility Ratings for performingcompleting the Extreme
Temperature Assessment in accordance with Requirement R3. [Violation Risk Factor:
High] [Time Horizon: Long-term Planning]
M5. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
such as electronic or hard copies of the documentation specifying the criteria for
acceptable System steady state voltage limits and, post-Contingency voltage

Draft 2 of TPL-008-1
July 2024

Page 5 of 30

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

deviations, and applicable Facility Ratings for performingcompleting the Extreme
Temperature Assessment in accordance with Requirement R5.
R6. Each responsible entity, as identified in Requirement R1, shall define and document
the criteria or methodology used in the Extreme Temperature Assessment analysis to
identify instability, uncontrolled separation, or Cascading. within an Interconnection.
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
M6. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
such as electronic or hard copy documentation of the defined and documented
criteria or methodology used to identify instability, uncontrolled separation, or
Cascading used in the Extreme Temperature Assessment analysis in accordance with
Requirement R6within an Interconnection.
R7. Each responsible entity, as identified in Requirement R1, shall identify Contingencies
used in performing the Extreme Temperature Assessmentthe planning events for each
of the event categoriescategory in Table 1 that are expected to produce more severe
System impacts withinon its planning areaportion of the Bulk Electric System. The
rationale for those Contingencies selected for evaluation shall be available as
supporting information. [Violation Risk Factor: High] [Time Horizon: Long-term
Planning]
M7. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
such as electronic or hard copy documentation that it has identified Contingencies for
performingof the Extreme Temperature Assessment planning events for each of the
event categoriescategory in Table 1 that are expected to produce more severe System
impacts withinon its planning area and the portion of the Bulk Electric System along
with supporting rationale, in accordance with Requirement R7, such as electronic or
hard copies of documents identifying the Contingencies with supporting rationale..
R8. Each responsible entity, as identified in Requirement R1, shall complete ansteady
state and transient stability analyses in its Extreme Temperature Assessment of the
Long-Term Transmission Planning Horizon at least once every five calendar years,
using the benchmark planning cases Contingencies identified in Requirement R7, and
the System models identified in Requirement R3 and R4, and the Contingencies
identified in Requirement R7 for each of the event categories in Table 1, and shall
document the assumptions and results of the steady state and transient stability
analyses. The Extreme Temperature Assessment shall include the following.: [Violation
Risk Factor: High] [Time Horizon: Long-term Planning]
8.1. AssessmentAnalysis of the benchmark planning cases developed under in
accordance with Requirement R4, for one of the years in the Long-Term
Transmission Planning Horizon. The rationale for the year selected for evaluation
shall be available as supporting information. Part 4.1.

Draft 2 of TPL-008-1
July 2024

Page 6 of 30

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

8.2. Sensitivity analysis to demonstrate the impact of changes to the basic
assumptions used in the model. To accomplish this, the sensitivity analysis in the
Extreme Temperature Assessment shall include, at a minimum, changes to one
of the following conditions:
•

Generation;

•

Real and reactive forecasted Load; or

•

Transfers

8.2. Analysis of the sensitivity cases developed in accordance with Requirement R4
Part 4. 2.
M8. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
that it performed ancompleted the steady state and transient stability analyses in its
Extreme Temperature Assessment, such as electronic or hard copies of the
assessmentanalyses, meeting all the requirements in Requirement R8.
R9. Each responsible entity, as identified in Requirement R1, shall develop a Corrective
Action Plan(s) (CAPs) when the assessment of a benchmark planning case study results
indicate the, in accordance with Requirement R8 Part 8.1, indicates its portion of the
Bulk Electric System is unable to meet performance requirements for Table 1 P0 or P1
Contingencies. TheFor each Corrective Action Plan, the responsible entitiesentity shall
share: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
9.1. Make their CAPs with,CAP available and solicit feedback from, applicable
regulatory authorities or governing bodies responsible for retail electric service
issues. In addition, where Load shed is allowed as an element of a CAP for the
Table 1 P1 Contingency, the responsible entity shall document
8.3.9.2.
Document the alternative(s) considered, as mentioned in Requirement
R10, and notify the applicable regulatory authorities or governing bodies
responsible for retail electric service issues. Revisions to the CAP(s) are allowed
in subsequent Extreme Temperature Assessments, but the planned System shall
continue to meet the performance requirements. [Violation Risk Factor: High]
[Time Horizon: Long-term Planning] when Non-Consequential Load Loss is
utilized as an element of a CAP for the Table 1 P1 Contingency.
9.3. Be permitted to utilize Non-Consequential Load Loss as an interim solution,
which normally is not permitted in Table 1, in situations that are beyond the
control of the Planning Coordinator or Transmission Planner that prevent the
implementation of a Corrective Action Plan in the required timeframe. The use
of Non-Consequential Load Loss as an interim solution in this situation is
permitted, provided that each responsible entity documents the situation
causing the problem, alternatives evaluated, and takes actions to resolve the
situation.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

9.4. Be allowed to have revisions to the CAP in subsequent Extreme Temperature
Assessments, provided that the planned BES shall continue to meet the
performance requirements of Table 1.
M9. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copy documentation, of each CAP developed for its Extreme
Temperature Assessment, including any revision history, when the assessment of the
benchmark planning cases indicate its portion of the BES is unable to meet
performance requirements for Table 1 P0 or P1 Contingencies in accordance with
Requirement R9.
R10. Each responsible entity, as identified in Requirement R1, shall evaluate and document
possible actions for the following: [Violation Risk Factor: Lower] [Time Horizon: Longterm Planning]
10.1. Benchmark planning cases where possible actions are designed to mitigate the
consequences and adverse impacts when the study results indicate the System
could result in instability, uncontrolled separation, or Cascading for the Table 1
P2, P4, and P7 Contingencies.
10.2. Sensitivity cases where possible actions are designed to mitigate failures to
meet the performance requirements in Table 1 for category P0, P1, P2, P4, and
P7 Contingencies.
M10. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
such as electronic or hard copy documentation of a CAP, including any revision history,
when the benchmark planning case study results indicate the System is unable to
meet performance requirements for the Table 1 P0 or P1 Contingencies in accordance
with Requirement R9. that it evaluated and documentdocumented possible actions
designed to reduce the likelihood or mitigate the consequences and adverse impacts
when the benchmark planning case study results indicate the System could result in
instability, uncontrolled separation, or Cascading for the Table 1 P2, P4, P5, and P7
Contingencies. [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning] Each
responsible entity, as identified in Requirement R1, shall provide the dated evidence
that it evaluated and documented possible actions designed to reduce the likelihood
or mitigate the consequences and adverse impacts when the benchmark planning case
study results indicate the System could result in instability, uncontrolled separation, or
Cascading for the Table 1 P2, P4, P5, and P7 Contingencies in accordance with
Requirement R10, such as electronic or hard copies of the assessment detailing such
actions.
R9.R11. Each responsible entity, as identified in Requirement R1, shall provide its Extreme
Temperature Assessment results within 60 calendar days of a request to any
functional entity that has a reliability related need and submits a written request
for the information. [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
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M11. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as email notices, documentation of updated web pages, postal receipts showing
recipient; or a demonstration of a public posting that it provided its Extreme
Temperature Assessment to any functional entity who has a reliability need within 60
calendar days of a written request.

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C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) 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 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 responsible entity shall retain evidence of compliance with each
requirement in this standard for five calendar years or one complete
Extreme Temperature Assessment cycle, whichever is longer.

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” 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.

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Table 1.1: Contingencies and Performance CriteriaCategory
See Footnote 2 for BES Level
Category

Initial Condition

Facility Voltage Level of Contingency

Steady State Performance Criteria

Stability Performance Criteria
Corrective Action Plan Required

Draft 2 of TPL-008-1
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Event

P0Fault type
Applicable to:
• BES level 200 kV and above
• Any common structure that includes a Facility 200kV and above
Reference Voltages:
• Non-generator step up transformer outage events, the reference voltage
applies to the low-side winding.
• Generator and generator step-up transformer outage events, the reference
voltage applies to the BES connected voltage (high-side of the step-up
transformer).
Evaluation for uncontrolled separation or
• Applicable
• Applicable
Cascading, as defined in Requirement R6.
Facility Ratings
Facility ratings
shall not be
shall not be
exceeded.
exceeded
• System steady • System steady
state voltages
state voltages
shall be within
shall be within
acceptable
acceptable
limits as
limits as
defined in
defined in
Requirement
Requirement
R5.
R5.
Initialization
Evaluation for instability, uncontrolled
without oscillation
separation, or Cascading, as defined in
Requirement R6.
Yes (See
Yes (See
No (See Requirement R10)
Requirement R9)
Requirement R9)

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1.1: Contingencies and Performance CriteriaCategory
See Footnote 2 for BES Level
Category

Initial Condition

Non-Consequential Load Loss Allowed

Draft 2 of TPL-008-1
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Event

P0Fault type

No (See
Requirement R9)

Yes (See
Requirement R9)

Yes

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1: Contingencies and Performance Criteria
Category
P0
No Contingency

P1
Single Contingency

P2
Single Contingency

P4
Multiple Contingency
(Fault plus stuck
breaker6)

Draft 2 of TPL-008-1
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Initial Condition
Normal System

Normal System

Normal System

Normal System

Event

Fault Type 1

None

N/A

Loss of one of the following:
1. Generator
2. Transmission Circuit
3. Transformer
4. Shunt Device2Device3

3Ø

5. Single Pole of a DC line

SLG

1. Opening of a line section w/o a fault 3Fault 4

N/A

2. Bus Section Fault

SLG

3. Internal Breaker Fault5
(non-Bus-tie Breaker)

SLG

1. Internal Breaker Fault4
4. (non-Fault (Bus-tie Breaker)5

SLG

Loss of multiple Elements caused by a stuck
breaker6(non-Bus-tie Breaker) attempting to clear a
Fault on one of the following:
1. Generator
2. Transmission Circuit
3. Transformer
4. Shunt Device3
5. Bus Section

SLG

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6. Loss of multiple Elements caused by a stuck
breaker6 (Bus-tie Breaker) attempting to clear a
Fault on the associated bus
P7
Multiple Contingency
(Common Structure)

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Normal System

Internal Breaker Fault (Bus-tie Breaker)4The loss of:
1. Any two adjacent (vertically or horizontally)
circuits on common structure
1.2. Loss of a bipolar DC line

SLG

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1: Contingencies and Performance Criteria
Category

P4
Multiple Contingency
(Fault plus stuck
breaker10)

Initial Condition

Normal System

Event
Loss of multiple elements caused by a stuck breaker5(non-Bus-tie
Breaker) attempting to clear a Fault on one of the following:
5. Generator
6. Transmission Circuit
7. Transformer
8. Shunt Device2
9. Bus Section
10. Loss of multiple elements caused by a stuck breaker5 (Bus-tie
Breaker) attempting to clear a Fault on the associated bus

P5
Multiple Contingency
(Fault plus nonredundant component of
a Protection System
failure to operate)
P7
Multiple Contingency
(Common Structure)

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Fault Type 1

SLG

SLG

Normal System

Delayed Fault Clearing due to the failure of a non-redundant component of a Protection
System7 protecting the Faulted element to operate as designed, for one of the following:
1. Generator
2. Transmission Circuit
3. Transformer
4. Shunt Device2
5. Bus Section

Normal System

The loss of:
1. Any two adjacent (vertically or horizontally) circuits on common
structure 6
2. Loss of a bipolar DC line

SLG

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 –.2: Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)Requirements
Steady State
Performance
Requirements

•
•

Stability
Performance
Requirements

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July 2024

P0

Applicable Facility
Ratings shall not be
exceeded.
System steady state
voltages shall be
within acceptable
limits as defined in
Requirement R5.

1. Unless specified
otherwise, simulate
Normal Clearing of
faults. Single line to
ground (SLG) or threephase (3Ø) are the
fault types that must
be evaluated in
Stability simulations
for the event
described. A 3Ø or a
double line to ground
fault study indicating
the criteria are being
met is sufficient
evidence that a SLG
condition would also
meet the criteria.
2. Requirements which
are applicable to
shunt devices also

P1

Applicable Facility
ratings shall not be
exceeded.
• System steady state
voltages shall be
within acceptable
limits as defined in
Requirement R5.
Instability, uncontrolled
separation, or Cascading,
as defined in Requirement
R6, shall not occur.
•

P2

P4

P7

Instability, uncontrolled separation, or Cascading, as defined in
Requirement R6, shall not occur.

Instability, uncontrolled separation, or Cascading, as defined in
Requirement R6, shall not occur.

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Table 1 –.2: Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)Requirements
apply to FACTS
devices that are
connected to ground.
3. Opening one end of a
line section without a
fault on a normally
networked
Transmission circuit
such that the line is
possibly serving Load
radial from a single
source point.
4. An internal breaker
fault means a breaker
failing internally, thus
creating aThe System
fault which must be
cleared by protection
on both sides of the
breaker.
5. A stuck breaker
means that for a gangoperated breaker, all
three phases of the
breaker have
remained closed. For
an independent pole
operated (IPO) or an
independent pole
tripping (IPT) breaker,
only one pole is
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Table 1 –.2: Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)Requirements
assumed toshall
remain closed. A stuck
breaker results in
Delayed Fault
Clearing.
6. Excludes circuits that
share a common
structure (Planning
event P7) for one mile
or less.
7. For purposes of this
standard, nonredundant
components of a
Protection System to
consider arestable.
Instability,
uncontrolled
separation, or
Cascading, as follows:
A single protective relay
which responds to
electrical quantities,
without an alternative
(which may or maydefined
in Requirement R6, shall
not respond to electrical
quantities) that provides
comparable Normal
Clearing times;occur.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 –.2: Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)Requirements
a. A single
communications
system associated
with protective
functions,
necessary for
correct operation
of a
communicationaided protection
scheme required
for Normal
Clearing (an
exception is a
single
communications
system that is
both monitored
and reported at a
Control Center);
b. A single station dc
supply associated
with protective
functions required
for Normal
Clearing (an
exception is a
single station dc
supply that is both
monitored and
reported at a
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Table 1 –.2: Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)Requirements
Control Center for
both low voltage
and open circuit);
A single control circuitry
(including auxiliary relays
and lockout relays)
associated with protective
functions, from the dc
supply through and
including the trip coil(s) of
the circuit breakers or
other interrupting devices,
required for Normal
Clearing (the trip coil may
be excluded if it is both
monitored and reported
at a Control Center).
Requirements for Benchmark Planning Case Assessment Results
Corrective Action
Plan Required

Yes (See Requirement R9)

Yes (See Requirement R9)

No (See Requirement R10)

Non-Consequential
Load Loss Allowed
Interruption of
Firm Transmission
Service Allowed

No (See Requirement R9)

Yes (See Requirement R9)

Yes

Yes

Yes

Yes

Requirements for Sensitivity Case Assessment Results

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 –.2: Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)Requirements
Corrective Action
Plan Required

No (See Requirement R10)

No (See Requirement R10)

No (See Requirement R10)

Non-Consequential
Load Loss Allowed
Interruption of
Firm Transmission
Service Allowed

Yes

Yes

Yes

Yes

Yes

Yes

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1.3 – Steady State & Stability Performance Footnotes
1. Unless specified otherwise, simulate Normal Clearing of faults. Single line to ground (SLG) or three-phase (3Ø) are the fault types that
must be evaluated in Stability simulations for the event described. A 3Ø or a double line to ground fault study indicating the criteria
are being met is sufficient evidence that a SLG condition would also meet the criteria.
2. Facility voltage level of Contingency is applicable to:
a. BES level 200 kV and above (referenced Contingency voltage)
b. For P7 events include Contingencies that have at least one 200kV voltage and above Facilities on common structure that has more
than one mile in length.
c. For non-generator step up transformer outage events, the reference voltage, as used in footnote 2a, applies to the low-side
winding (excluding tertiary windings). For generator and Generator Step Up transformer outage events, the reference voltage
applies to the BES connected voltage (high-side of the Generator Step Up transformer). Requirements which are applicable to
transformers also apply to variable frequency transformers and phase shifting transformers.
3. Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
4. Opening one end of a line section without a fault on a normally networked Transmission circuit such that the line is possibly serving
Load radial from a single source point.
5. An internal breaker fault means a breaker failing internally, thus creating a System fault which must be cleared by protection on both
sides of the breaker.
6. A stuck breaker means that for a gang-operated breaker, all three phases of the breaker have remained closed. For an independent
pole operated (IPO) or an independent pole tripping (IPT) breaker, only one pole is assumed to remain closed. A stuck breaker results
in Delayed Fault Clearing.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels
Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R1.

N/A

N/A

N/A

The Planning Coordinator, in
conjunction with its
Transmission Planner(s), failed
to determine and identify
individual and joint
responsibilities for performing
the required studies
forcompleting the Extreme
Temperature Assessment.

R2.

N/A

N/A

The responsible entity did not
select anat least one extreme
heat benchmark event or
extreme cold benchmark
temperature event from the
ERO approved benchmark
library for performing the
Extreme Temperature
Assessment.

The responsible entity did not
select an extreme heat
benchmark event and extreme
cold benchmark temperature
event from the ERO approved
benchmark library for
performing the Extreme
Temperature Assessment.

R3.

N/A

N/A

N/A

The Planning Coordinator did
not develop or implement a
process for coordinating the
development of benchmark
planning cases among
impacted adjacent Planning
Coordinator(s), Transmission
Planner(s), and other
designated study entities,

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R#

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL
within the same
Interconnection.
OR
The Planning Coordinator
developed and implemented a
process for coordinating the
development of benchmark
planning cases among
impacted adjacent Planning
Coordinator(s), Transmission
Planner(s), and other
designated study entities, but
this process did not define
within the planning study area
boundary based off the
selected benchmark events.
OR
The Planning Coordinator
developed and implemented a
process for coordinating the
development of benchmark
planning cases among
impacted Planning
Coordinator(s), Transmission
Planner(s), and other
designated study entitiessame
Interconnection, but this
process did not modify the
benchmark planning cases to

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
include seasonal and
temperature dependent
adjustments load, generation,
Transmission, and transfers.

R4.

N/A

N/A

N/A

The responsible entity did not
develop or maintain System
models of the responsible
entity’sbenchmark planning
areacases or sensitivity cases
for performing the Extreme
Temperature Assessment.
OR
The responsible entity
developed and maintained
System modelsbenchmark
planning cases or sensitivity
cases for performing the
Extreme Temperature
Assessment, but the System
model did not use data
consistent with that provided
in accordance with the MOD032 standard supplemented by
other sources as needed.

R5.

N/A

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July 2024

N/A

N/A

The responsible entity, as
determined in Requirement

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
R1, did not have criteria for
acceptable System steady
state voltage limits and, postContingency voltage
deviations, and applicable
Facility Ratings for performing
Extreme Temperature
Assessment.

R6.

N/A

N/A

N/A

The responsible entity failed to
define and document, the
criteria or methodology used
in the analysis to identify
System instability,
uncontrolled separation, or
Cascading. within an
Interconnection.

R7.

N/A

N/A

The responsible entity, as
determined in Requirement
R1, identified Contingencies
for performing Extreme
Temperature Assessment for
each of the event
categoriesplanning events in
Table 1 that are expected to
produce more severe System
impacts within its planning
area, but did not include the
rationale for those
Contingencies selected for

The responsible entity, as
determined in Requirement
R1, did not identify
Contingencies for performing
Extreme Temperature
Assessment for each of the
event categoriesplanning
events in Table 1 that are
expected to produce more
severe System impacts within
its planning area.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

evaluation as supporting
documentation.
R8.

The responsible entity, as
determined in Requirement
R1, completed an Extreme
Temperature Assessment,
but it was
completedperformed less
than or equal to six months
late.

The responsible entity, as
determined in Requirement
R1, completed an Extreme
Temperature Assessment, but
it was completedperformed
more than six months but less
than or equal to 12 months
late.

The responsible entity, as
determined in Requirement
R1, completed an Extreme
Temperature Assessment, but
it was completedperformed
more than 12 months but less
than or equal to than 18
months late.

The responsible entity, as
determined in Requirement
R1, completedperformed an
Extreme Temperature
Assessment, but it was more
than 18 months late.
OR
The responsible entity, as
determined in Requirement
R1, did not completeperform
an Extreme Temperature
Assessment.
OR
The responsible entity, as
determined in Requirement
R1, completedperformed an
Extreme Temperature
Assessment, but it was missing
one or more of the required
elements in Requirement R8.

R9.

N/A

Draft 2 of TPL-008-1
July 2024

N/A

The responsible entity, as
determined in Requirement
R1, developed a CAPCorrective

The responsible entity, as
determined in Requirement
R1, failed to develop a

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

Action Plan meeting each of
the elements in Requirement
R9, but failed to make their
Corrective Action Plan
available to, or solicit feedback
from, applicable regulatory
authorities or governing
bodies responsible for retail
electric service issues.

Corrective Action Plan meeting
each of the elements of
Requirement R9 when the
benchmark planning case
study results indicate the
System is unable to meet
performance requirements for
the Table 1 P0 or P1
Contingencies.

R10.

N/A

N/A

N/A

Each responsible entity, as
determined in Requirement
R1, failed to evaluate and
document possible actions
designed to reduce the
likelihood or, mitigate the
consequences, and adverse
impacts when the benchmark
planning case study results
indicate the System could
result in instability,
uncontrolled separation, or
Cascading for the Table 1 P2,
P4, P5, and P7 Contingencies.

R11.

The responsible entity, as
determined in Requirement
R1, distributed its Extreme
Temperature Assessment

The responsible entity, as
determined in Requirement
R1, distributed its Extreme
Temperature Assessment

The responsible entity, as
determined in Requirement
R1, distributed its Extreme
Temperature Assessment

The responsible entity, as
determined in Requirement
R1, distributed its Extreme
Temperature Assessment

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Violation Severity Levels

R#

Lower VSL
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 60 days but
less than or equal to 80 days
following the request.

Moderate VSL

High VSL

results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 80 days but
less than or equal to 100 days
following the request.

results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 100 days but
less than or equal to 120 days
following the request.

Severe VSL
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 120 days
following the request.
OR
The responsible entity, as
determined in Requirement
R1, did not distribute its
Extreme Temperature
Assessment results to
functional entities having a
reliability related need who
requested the information in
writing.

D. Regional Variances
None.

E. Associated Documents
•

Implementation Plan for 2023-07

•

Technical Rationale Document

•

Consideration of Issues and Directives for FERC Order 896.

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Version History
Version

Date

Action

Change
Tracking

1

TBD

Addressing FERC Order 896

New Standard

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Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

This is the second draft of the proposed standard posted for a 38-day formal comment period
with additional ballot.
Completed Actions

Date

Standards Committee approved Standard Authorization Request (SAR)
for posting

July 19, 2023

SAR posted for comment

August 8 – September 27,
2023

45-day formal comment period with initial ballot

March 20 – May 3, 2024

Anticipated Actions

Date

38-day formal comment period with additional ballot

July 16 – August 22, 2024

45-day formal comment period with additional ballot

September 2024

10-day final ballot

November 2024

Board adoption

December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

New or Modified Term(s) Used in NERC Reliability Standards

This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):

Extreme Temperature Assessment – Documented evaluation of future TransmissionBulk
Electric System performance for extreme heat and extreme cold temperature benchmark
events.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements for
Extreme Temperature Events

2.

Number:

TPL-008-1

3.

Purpose:

Establish requirements for Transmission system planning performance
forrequirements to develop a Bulk Power System (BPS) that will operate
reliably during extreme heat and extreme cold temperature events.

3.

Applicability:
3.1. Functional Entities:
4.1.1. Transmission Planner
4.1.2. Planning Coordinator

4.

Effective Date: See Implementation Plan for Project 2023-07.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

B. Requirements and Measures
R1. Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
determine and identify each entity’s individual and joint responsibilities for
performing the studies needed to completecompleting the Extreme Temperature
Assessment. [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
M1.Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
provide documentation of each entity’s individual and joint responsibilities, such as
meeting minutes, agreements, copies of procedures or protocols in effect between
entities or between departments of a vertically integrated system, or email
correspondence that identifies an agreement has been reached on individual and joint
responsibilities for performing the studies needed to completecompleting the Extreme
Temperature Assessment.
R2. Each responsible entity, as identified in Requirement R1, shall select at least one
extreme heat benchmark temperature event and at least one extreme cold
benchmark temperature event, from the approved benchmark library, approved and
maintained by the Electric Reliability Organization (ERO), for performingcompleting
the Extreme Temperature Assessment. [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
M2. Each responsible entity, as identified in Requirement R1, shall have evidence in either
electronic or hard copy format of its selectedselecting at least one extreme heat
benchmark event and at least one extreme cold benchmark temperature event for
performingcompleting the Extreme Temperature Assessment.
R3. Each Planning Coordinator shall develop and implement a process for coordinating the
development of benchmark planning cases among, using the selected benchmark
temperature events identified in Requirement R2, among adjacent impacted Planning
Coordinator(s), Transmission Planner(s), and other designated study entities based on
the selected benchmark events as identified in Requirement R2., within an
Interconnection. This process shall: include seasonal and temperature dependent
adjustments for Load, generation, Transmission, and transfers to represent the
selected benchmark temperature events. [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
3.1. Define the planning study area boundary based on the selected benchmark
events.
3.2. Modify the benchmark planning cases to include seasonal and temperature
dependent adjustment for Load, generation, Transmission, and transfers which
represents the selected benchmark events.
M3. Each Planning Coordinator shall providehave dated evidence ofthat it developed and
implemented a process for coordinating the development of benchmark planning
cases among impacted Planning Coordinators, and Transmission Planner(s) as
specified in Requirement R3. Acceptable evidence may include, but is not limited to,
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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

the following dated documentation (electronic or hardcopy format): records defining
the planning study area boundary based on the selected benchmark events and
modifications to the benchmark planning cases that includeincludes seasonal and
temperature dependent adjustment for Load, generation, Transmission, and transfers
whichto represent the selected benchmark temperature events.
R4.

Each responsible entity, as identified in Requirement R1, shall develop and maintain
System models within its planning area for performing the Extreme Temperature
Assessment. The System models shall use the coordination process developed in
accordance with Requirement R3 and data consistent with that provided in
accordance with the MOD-032 standard, supplemented by other sources as needed,
and shall represent projected System conditions based on the selected benchmark
events as identified in Requirement R2.to develop and maintain the following:
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. Each responsible entity,Benchmark planning cases that include seasonal and
temperature dependent adjustments for Load, generation, Transmission, and
transfers to represent the System conditions of the selected benchmark
temperature events as identified in Requirement R2 for one of the years in the
Long-Term Transmission Planning Horizon. The rationale for the year selected for
evaluation shall be available as supporting information. R1,This establishes
Category P0 as the normal System condition in Table 1.
4.2. Sensitivity cases to demonstrate the impact of changes to the basic assumptions
used in the benchmark planning cases. To accomplish this, the sensitivity cases
shall have changes to at least one of the following conditions:
•

Generation;

•

Real and reactive forecasted Load; or

•

Transfers.

M4. Each responsible entity shall have dated evidence in either electronic or hard copy
format that it developed and maintained System models of the responsible
entity’sbenchmark planning areacases and sensitivity cases for performingcompleting
the Extreme Temperature Assessment.
R5. Each responsible entity, as identified in Requirement R1, shall have criteria for
acceptable System steady state voltage limits and, post-Contingency voltage
deviations, and applicable Facility Ratings for performingcompleting the Extreme
Temperature Assessment in accordance with Requirement R3. [Violation Risk Factor:
High] [Time Horizon: Long-term Planning]
M5. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
such as electronic or hard copies of the documentation specifying the criteria for
acceptable System steady state voltage limits and, post-Contingency voltage

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deviations, and applicable Facility Ratings for performingcompleting the Extreme
Temperature Assessment in accordance with Requirement R5.
R6. Each responsible entity, as identified in Requirement R1, shall define and document
the criteria or methodology used in the Extreme Temperature Assessment analysis to
identify instability, uncontrolled separation, or Cascading. within an Interconnection.
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
M6. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
such as electronic or hard copy documentation of the defined and documented
criteria or methodology used to identify instability, uncontrolled separation, or
Cascading used in the Extreme Temperature Assessment analysis in accordance with
Requirement R6within an Interconnection.
R7. Each responsible entity, as identified in Requirement R1, shall identify Contingencies
used in performing the Extreme Temperature Assessmentthe planning events for each
of the event categoriescategory in Table 1 that are expected to produce more severe
System impacts withinon its planning areaportion of the Bulk Electric System. The
rationale for those Contingencies selected for evaluation shall be available as
supporting information. [Violation Risk Factor: High] [Time Horizon: Long-term
Planning]
M7. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
such as electronic or hard copy documentation that it has identified Contingencies for
performingof the Extreme Temperature Assessment planning events for each of the
event categoriescategory in Table 1 that are expected to produce more severe System
impacts withinon its planning area and the portion of the Bulk Electric System along
with supporting rationale, in accordance with Requirement R7, such as electronic or
hard copies of documents identifying the Contingencies with supporting rationale..
R8. Each responsible entity, as identified in Requirement R1, shall complete ansteady
state and transient stability analyses in its Extreme Temperature Assessment of the
Long-Term Transmission Planning Horizon at least once every five calendar years,
using the benchmark planning cases Contingencies identified in Requirement R7, and
the System models identified in Requirement R3 and R4, and the Contingencies
identified in Requirement R7 for each of the event categories in Table 1, and shall
document the assumptions and results of the steady state and transient stability
analyses. The Extreme Temperature Assessment shall include the following.: [Violation
Risk Factor: High] [Time Horizon: Long-term Planning]
8.1. AssessmentAnalysis of the benchmark planning cases developed under in
accordance with Requirement R4, for one of the years in the Long-Term
Transmission Planning Horizon. The rationale for the year selected for evaluation
shall be available as supporting information. Part 4.1.

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8.2. Sensitivity analysis to demonstrate the impact of changes to the basic
assumptions used in the model. To accomplish this, the sensitivity analysis in the
Extreme Temperature Assessment shall include, at a minimum, changes to one
of the following conditions:
•

Generation;

•

Real and reactive forecasted Load; or

•

Transfers

8.2. Analysis of the sensitivity cases developed in accordance with Requirement R4
Part 4. 2.
M8. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
that it performed ancompleted the steady state and transient stability analyses in its
Extreme Temperature Assessment, such as electronic or hard copies of the
assessmentanalyses, meeting all the requirements in Requirement R8.
R9. Each responsible entity, as identified in Requirement R1, shall develop a Corrective
Action Plan(s) (CAPs) when the assessment of a benchmark planning case study results
indicate the, in accordance with Requirement R8 Part 8.1, indicates its portion of the
Bulk Electric System is unable to meet performance requirements for Table 1 P0 or P1
Contingencies. TheFor each Corrective Action Plan, the responsible entitiesentity shall
share: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
9.1. Make their CAPs with,CAP available and solicit feedback from, applicable
regulatory authorities or governing bodies responsible for retail electric service
issues. In addition, where Load shed is allowed as an element of a CAP for the
Table 1 P1 Contingency, the responsible entity shall document
8.3.9.2.
Document the alternative(s) considered, as mentioned in Requirement
R10, and notify the applicable regulatory authorities or governing bodies
responsible for retail electric service issues. Revisions to the CAP(s) are allowed
in subsequent Extreme Temperature Assessments, but the planned System shall
continue to meet the performance requirements. [Violation Risk Factor: High]
[Time Horizon: Long-term Planning] when Non-Consequential Load Loss is
utilized as an element of a CAP for the Table 1 P1 Contingency.
9.3. Be permitted to utilize Non-Consequential Load Loss as an interim solution,
which normally is not permitted in Table 1, in situations that are beyond the
control of the Planning Coordinator or Transmission Planner that prevent the
implementation of a Corrective Action Plan in the required timeframe. The use
of Non-Consequential Load Loss as an interim solution in this situation is
permitted, provided that each responsible entity documents the situation
causing the problem, alternatives evaluated, and takes actions to resolve the
situation.

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9.4. Be allowed to have revisions to the CAP in subsequent Extreme Temperature
Assessments, provided that the planned BES shall continue to meet the
performance requirements of Table 1.
M9. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copy documentation, of each CAP developed for its Extreme
Temperature Assessment, including any revision history, when the assessment of the
benchmark planning cases indicate its portion of the BES is unable to meet
performance requirements for Table 1 P0 or P1 Contingencies in accordance with
Requirement R9.
R10. Each responsible entity, as identified in Requirement R1, shall evaluate and document
possible actions for the following: [Violation Risk Factor: Lower] [Time Horizon: Longterm Planning]
10.1. Benchmark planning cases where possible actions are designed to mitigate the
consequences and adverse impacts when the study results indicate the System
could result in instability, uncontrolled separation, or Cascading for the Table 1
P2, P4, and P7 Contingencies.
10.2. Sensitivity cases where possible actions are designed to mitigate failures to
meet the performance requirements in Table 1 for category P0, P1, P2, P4, and
P7 Contingencies.
M10. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
such as electronic or hard copy documentation of a CAP, including any revision history,
when the benchmark planning case study results indicate the System is unable to
meet performance requirements for the Table 1 P0 or P1 Contingencies in accordance
with Requirement R9. that it evaluated and documentdocumented possible actions
designed to reduce the likelihood or mitigate the consequences and adverse impacts
when the benchmark planning case study results indicate the System could result in
instability, uncontrolled separation, or Cascading for the Table 1 P2, P4, P5, and P7
Contingencies. [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning] Each
responsible entity, as identified in Requirement R1, shall provide the dated evidence
that it evaluated and documented possible actions designed to reduce the likelihood
or mitigate the consequences and adverse impacts when the benchmark planning case
study results indicate the System could result in instability, uncontrolled separation, or
Cascading for the Table 1 P2, P4, P5, and P7 Contingencies in accordance with
Requirement R10, such as electronic or hard copies of the assessment detailing such
actions.
R9.R11. Each responsible entity, as identified in Requirement R1, shall provide its Extreme
Temperature Assessment results within 60 calendar days of a request to any
functional entity that has a reliability related need and submits a written request
for the information. [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
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M11. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as email notices, documentation of updated web pages, postal receipts showing
recipient; or a demonstration of a public posting that it provided its Extreme
Temperature Assessment to any functional entity who has a reliability need within 60
calendar days of a written request.

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C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) 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 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 responsible entity shall retain evidence of compliance with each
requirement in this standard for five calendar years or one complete
Extreme Temperature Assessment cycle, whichever is longer.

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” 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.

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Table 1.1: Contingencies and Performance CriteriaCategory
See Footnote 2 for BES Level
Category

Initial Condition

Facility Voltage Level of Contingency

Steady State Performance Criteria

Stability Performance Criteria
Corrective Action Plan Required

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Event

P0Fault type
Applicable to:
• BES level 200 kV and above
• Any common structure that includes a Facility 200kV and above
Reference Voltages:
• Non-generator step up transformer outage events, the reference voltage
applies to the low-side winding.
• Generator and generator step-up transformer outage events, the reference
voltage applies to the BES connected voltage (high-side of the step-up
transformer).
Evaluation for uncontrolled separation or
• Applicable
• Applicable
Cascading, as defined in Requirement R6.
Facility Ratings
Facility ratings
shall not be
shall not be
exceeded.
exceeded
• System steady • System steady
state voltages
state voltages
shall be within
shall be within
acceptable
acceptable
limits as
limits as
defined in
defined in
Requirement
Requirement
R5.
R5.
Initialization
Evaluation for instability, uncontrolled
without oscillation
separation, or Cascading, as defined in
Requirement R6.
Yes (See
Yes (See
No (See Requirement R10)
Requirement R9)
Requirement R9)

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Table 1.1: Contingencies and Performance CriteriaCategory
See Footnote 2 for BES Level
Category

Initial Condition

Non-Consequential Load Loss Allowed

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Event

P0Fault type

No (See
Requirement R9)

Yes (See
Requirement R9)

Yes

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1: Contingencies and Performance Criteria
Category
P0
No Contingency

P1
Single Contingency

P2
Single Contingency

P4
Multiple Contingency
(Fault plus stuck
breaker6)

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Initial Condition
Normal System

Normal System

Normal System

Normal System

Event

Fault Type 1

None

N/A

Loss of one of the following:
1. Generator
2. Transmission Circuit
3. Transformer
4. Shunt Device2Device3

3Ø

5. Single Pole of a DC line

SLG

1. Opening of a line section w/o a fault 3Fault 4

N/A

2. Bus Section Fault

SLG

3. Internal Breaker Fault5
(non-Bus-tie Breaker)

SLG

1. Internal Breaker Fault4
4. (non-Fault (Bus-tie Breaker)5

SLG

Loss of multiple Elements caused by a stuck
breaker6(non-Bus-tie Breaker) attempting to clear a
Fault on one of the following:
1. Generator
2. Transmission Circuit
3. Transformer
4. Shunt Device3
5. Bus Section

SLG

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6. Loss of multiple Elements caused by a stuck
breaker6 (Bus-tie Breaker) attempting to clear a
Fault on the associated bus
P7
Multiple Contingency
(Common Structure)

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Normal System

Internal Breaker Fault (Bus-tie Breaker)4The loss of:
1. Any two adjacent (vertically or horizontally)
circuits on common structure
1.2. Loss of a bipolar DC line

SLG

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1: Contingencies and Performance Criteria
Category

P4
Multiple Contingency
(Fault plus stuck
breaker10)

Initial Condition

Normal System

Event
Loss of multiple elements caused by a stuck breaker5(non-Bus-tie
Breaker) attempting to clear a Fault on one of the following:
5. Generator
6. Transmission Circuit
7. Transformer
8. Shunt Device2
9. Bus Section
10. Loss of multiple elements caused by a stuck breaker5 (Bus-tie
Breaker) attempting to clear a Fault on the associated bus

P5
Multiple Contingency
(Fault plus nonredundant component of
a Protection System
failure to operate)
P7
Multiple Contingency
(Common Structure)

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Fault Type 1

SLG

SLG

Normal System

Delayed Fault Clearing due to the failure of a non-redundant component of a Protection
System7 protecting the Faulted element to operate as designed, for one of the following:
1. Generator
2. Transmission Circuit
3. Transformer
4. Shunt Device2
5. Bus Section

Normal System

The loss of:
1. Any two adjacent (vertically or horizontally) circuits on common
structure 6
2. Loss of a bipolar DC line

SLG

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Table 1 –.2: Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)Requirements
Steady State
Performance
Requirements

•
•

Stability
Performance
Requirements

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P0

Applicable Facility
Ratings shall not be
exceeded.
System steady state
voltages shall be
within acceptable
limits as defined in
Requirement R5.

1. Unless specified
otherwise, simulate
Normal Clearing of
faults. Single line to
ground (SLG) or threephase (3Ø) are the
fault types that must
be evaluated in
Stability simulations
for the event
described. A 3Ø or a
double line to ground
fault study indicating
the criteria are being
met is sufficient
evidence that a SLG
condition would also
meet the criteria.
2. Requirements which
are applicable to
shunt devices also

P1

Applicable Facility
ratings shall not be
exceeded.
• System steady state
voltages shall be
within acceptable
limits as defined in
Requirement R5.
Instability, uncontrolled
separation, or Cascading,
as defined in Requirement
R6, shall not occur.
•

P2

P4

P7

Instability, uncontrolled separation, or Cascading, as defined in
Requirement R6, shall not occur.

Instability, uncontrolled separation, or Cascading, as defined in
Requirement R6, shall not occur.

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Table 1 –.2: Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)Requirements
apply to FACTS
devices that are
connected to ground.
3. Opening one end of a
line section without a
fault on a normally
networked
Transmission circuit
such that the line is
possibly serving Load
radial from a single
source point.
4. An internal breaker
fault means a breaker
failing internally, thus
creating aThe System
fault which must be
cleared by protection
on both sides of the
breaker.
5. A stuck breaker
means that for a gangoperated breaker, all
three phases of the
breaker have
remained closed. For
an independent pole
operated (IPO) or an
independent pole
tripping (IPT) breaker,
only one pole is
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Table 1 –.2: Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)Requirements
assumed toshall
remain closed. A stuck
breaker results in
Delayed Fault
Clearing.
6. Excludes circuits that
share a common
structure (Planning
event P7) for one mile
or less.
7. For purposes of this
standard, nonredundant
components of a
Protection System to
consider arestable.
Instability,
uncontrolled
separation, or
Cascading, as follows:
A single protective relay
which responds to
electrical quantities,
without an alternative
(which may or maydefined
in Requirement R6, shall
not respond to electrical
quantities) that provides
comparable Normal
Clearing times;occur.

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Table 1 –.2: Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)Requirements
a. A single
communications
system associated
with protective
functions,
necessary for
correct operation
of a
communicationaided protection
scheme required
for Normal
Clearing (an
exception is a
single
communications
system that is
both monitored
and reported at a
Control Center);
b. A single station dc
supply associated
with protective
functions required
for Normal
Clearing (an
exception is a
single station dc
supply that is both
monitored and
reported at a
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Table 1 –.2: Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)Requirements
Control Center for
both low voltage
and open circuit);
A single control circuitry
(including auxiliary relays
and lockout relays)
associated with protective
functions, from the dc
supply through and
including the trip coil(s) of
the circuit breakers or
other interrupting devices,
required for Normal
Clearing (the trip coil may
be excluded if it is both
monitored and reported
at a Control Center).
Requirements for Benchmark Planning Case Assessment Results
Corrective Action
Plan Required

Yes (See Requirement R9)

Yes (See Requirement R9)

No (See Requirement R10)

Non-Consequential
Load Loss Allowed
Interruption of
Firm Transmission
Service Allowed

No (See Requirement R9)

Yes (See Requirement R9)

Yes

Yes

Yes

Yes

Requirements for Sensitivity Case Assessment Results

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Table 1 –.2: Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)Requirements
Corrective Action
Plan Required

No (See Requirement R10)

No (See Requirement R10)

No (See Requirement R10)

Non-Consequential
Load Loss Allowed
Interruption of
Firm Transmission
Service Allowed

Yes

Yes

Yes

Yes

Yes

Yes

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Table 1.3 – Steady State & Stability Performance Footnotes
1. Unless specified otherwise, simulate Normal Clearing of faults. Single line to ground (SLG) or three-phase (3Ø) are the fault types that
must be evaluated in Stability simulations for the event described. A 3Ø or a double line to ground fault study indicating the criteria
are being met is sufficient evidence that a SLG condition would also meet the criteria.
2. Facility voltage level of Contingency is applicable to:
a. BES level 200 kV and above (referenced Contingency voltage)
b. For P7 events include Contingencies that have at least one 200kV voltage and above Facilities on common structure that has more
than one mile in length.
c. For non-generator step up transformer outage events, the reference voltage, as used in footnote 2a, applies to the low-side
winding (excluding tertiary windings). For generator and Generator Step Up transformer outage events, the reference voltage
applies to the BES connected voltage (high-side of the Generator Step Up transformer). Requirements which are applicable to
transformers also apply to variable frequency transformers and phase shifting transformers.
3. Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
4. Opening one end of a line section without a fault on a normally networked Transmission circuit such that the line is possibly serving
Load radial from a single source point.
5. An internal breaker fault means a breaker failing internally, thus creating a System fault which must be cleared by protection on both
sides of the breaker.
6. A stuck breaker means that for a gang-operated breaker, all three phases of the breaker have remained closed. For an independent
pole operated (IPO) or an independent pole tripping (IPT) breaker, only one pole is assumed to remain closed. A stuck breaker results
in Delayed Fault Clearing.

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Violation Severity Levels
Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R1.

N/A

N/A

N/A

The Planning Coordinator, in
conjunction with its
Transmission Planner(s), failed
to determine and identify
individual and joint
responsibilities for performing
the required studies
forcompleting the Extreme
Temperature Assessment.

R2.

N/A

N/A

The responsible entity did not
select anat least one extreme
heat benchmark event or
extreme cold benchmark
temperature event from the
ERO approved benchmark
library for performing the
Extreme Temperature
Assessment.

The responsible entity did not
select an extreme heat
benchmark event and extreme
cold benchmark temperature
event from the ERO approved
benchmark library for
performing the Extreme
Temperature Assessment.

R3.

N/A

N/A

N/A

The Planning Coordinator did
not develop or implement a
process for coordinating the
development of benchmark
planning cases among
impacted adjacent Planning
Coordinator(s), Transmission
Planner(s), and other
designated study entities,

Draft 2 of TPL-008-1
July 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R#

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL
within the same
Interconnection.
OR
The Planning Coordinator
developed and implemented a
process for coordinating the
development of benchmark
planning cases among
impacted adjacent Planning
Coordinator(s), Transmission
Planner(s), and other
designated study entities, but
this process did not define
within the planning study area
boundary based off the
selected benchmark events.
OR
The Planning Coordinator
developed and implemented a
process for coordinating the
development of benchmark
planning cases among
impacted Planning
Coordinator(s), Transmission
Planner(s), and other
designated study entitiessame
Interconnection, but this
process did not modify the
benchmark planning cases to

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
include seasonal and
temperature dependent
adjustments load, generation,
Transmission, and transfers.

R4.

N/A

N/A

N/A

The responsible entity did not
develop or maintain System
models of the responsible
entity’sbenchmark planning
areacases or sensitivity cases
for performing the Extreme
Temperature Assessment.
OR
The responsible entity
developed and maintained
System modelsbenchmark
planning cases or sensitivity
cases for performing the
Extreme Temperature
Assessment, but the System
model did not use data
consistent with that provided
in accordance with the MOD032 standard supplemented by
other sources as needed.

R5.

N/A

Draft 2 of TPL-008-1
July 2024

N/A

N/A

The responsible entity, as
determined in Requirement

Page 25 of 30

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
R1, did not have criteria for
acceptable System steady
state voltage limits and, postContingency voltage
deviations, and applicable
Facility Ratings for performing
Extreme Temperature
Assessment.

R6.

N/A

N/A

N/A

The responsible entity failed to
define and document, the
criteria or methodology used
in the analysis to identify
System instability,
uncontrolled separation, or
Cascading. within an
Interconnection.

R7.

N/A

N/A

The responsible entity, as
determined in Requirement
R1, identified Contingencies
for performing Extreme
Temperature Assessment for
each of the event
categoriesplanning events in
Table 1 that are expected to
produce more severe System
impacts within its planning
area, but did not include the
rationale for those
Contingencies selected for

The responsible entity, as
determined in Requirement
R1, did not identify
Contingencies for performing
Extreme Temperature
Assessment for each of the
event categoriesplanning
events in Table 1 that are
expected to produce more
severe System impacts within
its planning area.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

evaluation as supporting
documentation.
R8.

The responsible entity, as
determined in Requirement
R1, completed an Extreme
Temperature Assessment,
but it was
completedperformed less
than or equal to six months
late.

The responsible entity, as
determined in Requirement
R1, completed an Extreme
Temperature Assessment, but
it was completedperformed
more than six months but less
than or equal to 12 months
late.

The responsible entity, as
determined in Requirement
R1, completed an Extreme
Temperature Assessment, but
it was completedperformed
more than 12 months but less
than or equal to than 18
months late.

The responsible entity, as
determined in Requirement
R1, completedperformed an
Extreme Temperature
Assessment, but it was more
than 18 months late.
OR
The responsible entity, as
determined in Requirement
R1, did not completeperform
an Extreme Temperature
Assessment.
OR
The responsible entity, as
determined in Requirement
R1, completedperformed an
Extreme Temperature
Assessment, but it was missing
one or more of the required
elements in Requirement R8.

R9.

N/A

Draft 2 of TPL-008-1
July 2024

N/A

The responsible entity, as
determined in Requirement
R1, developed a CAPCorrective

The responsible entity, as
determined in Requirement
R1, failed to develop a

Page 27 of 30

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

Action Plan meeting each of
the elements in Requirement
R9, but failed to make their
Corrective Action Plan
available to, or solicit feedback
from, applicable regulatory
authorities or governing
bodies responsible for retail
electric service issues.

Corrective Action Plan meeting
each of the elements of
Requirement R9 when the
benchmark planning case
study results indicate the
System is unable to meet
performance requirements for
the Table 1 P0 or P1
Contingencies.

R10.

N/A

N/A

N/A

Each responsible entity, as
determined in Requirement
R1, failed to evaluate and
document possible actions
designed to reduce the
likelihood or, mitigate the
consequences, and adverse
impacts when the benchmark
planning case study results
indicate the System could
result in instability,
uncontrolled separation, or
Cascading for the Table 1 P2,
P4, P5, and P7 Contingencies.

R11.

The responsible entity, as
determined in Requirement
R1, distributed its Extreme
Temperature Assessment

The responsible entity, as
determined in Requirement
R1, distributed its Extreme
Temperature Assessment

The responsible entity, as
determined in Requirement
R1, distributed its Extreme
Temperature Assessment

The responsible entity, as
determined in Requirement
R1, distributed its Extreme
Temperature Assessment

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels

R#

Lower VSL
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 60 days but
less than or equal to 80 days
following the request.

Moderate VSL

High VSL

results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 80 days but
less than or equal to 100 days
following the request.

results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 100 days but
less than or equal to 120 days
following the request.

Severe VSL
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 120 days
following the request.
OR
The responsible entity, as
determined in Requirement
R1, did not distribute its
Extreme Temperature
Assessment results to
functional entities having a
reliability related need who
requested the information in
writing.

D. Regional Variances
None.

E. Associated Documents
•

Implementation Plan for 2023-07

•

Technical Rationale Document

•

Consideration of Issues and Directives for FERC Order 896.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Version History
Version

Date

Action

Change
Tracking

1

TBD

Addressing FERC Order 896

New Standard

Draft 2 of TPL-008-1
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Page 30 of 30

Implementation Plan

Project 2023-07 Transmission System Planning Performance
Requirements for Extreme Weather
Reliability Standard TPL-008-1
Applicable Standard
•

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature
Events

Requested Retirement
•

Not applicable

Prerequisite Standard
•

Not applicable

Applicable Entities
•

Planning Coordinators

•

Transmission Planners

New Terms in the NERC Glossary of Terms
Proposed New Definition(s):

•

Extreme Temperature Assessment - Documented evaluation of future Bulk Electric System
performance for extreme heat and extreme cold temperature benchmark events.

Background

On June 15, 2023, FERC issued a Final Rulemaking directing NERC to develop a new or modified Reliability
Standard to address the lack of a long-term planning requirement(s) for extreme heat and cold weather
events. Specifically, FERC directed NERC to develop modifications to Reliability Standard TPL-001-5.1 or
develop a new Reliability Standard that requires the following: (1) development of benchmark planning
cases based on major prior extreme heat and cold weather events and/or meteorological projections; (2)
planning for extreme heat and cold weather events using steady state and transient stability analyses
expanded to cover a range of extreme weather scenarios including the expected resource mix’s availability
during extreme heat and cold weather conditions, and including the wide-area impacts of extreme heat
and cold weather; and (3) development of Corrective Action Plans that mitigate any instances where
performance requirements for extreme heat and cold weather events are not met.

RELIABILITY | RESILIENCE | SECURITY

Effective Date

The effective date for the proposed Reliability Standard is provided below. Where the standard drafting
team identified the need for a longer implementation period for compliance with a particular section of the
proposed Reliability Standard (e.g., an entire Requirement or a portion thereof), the additional time for
compliance with that section is specified below. These phased-in compliance dates represent the dates that
entities must begin to comply with that particular section of the Reliability Standard, even where the
Reliability Standard goes into effect at an earlier date.
TPL-008-1

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 twelve (12) 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 twelve (12) months after the date the standard
is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.

Phased-In Compliance Dates

Compliance Date for TPL-008-1 Requirement R1

Entities shall be required to comply with Requirement R1 upon the effective date of Reliability Standard
TPL-008-1.
Compliance Date for TPL-008-1 Requirements R2, R3, R4, R5, R6

Entities shall not be required to comply with Requirements R2, R3, R4, R5, and R6 until thirty-six (36) months
after the effective date of Reliability Standard TPL-008-1.
Compliance Date for TPL-008-1 Requirements R7, R8, R9, R10, R11

Entities shall not be required to comply with Requirements R7, R8, R9, R10, R11 until sixty (60) months after
the effective date of Reliability Standard TPL-008-1.

Implementation Plan
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | July 2024

2

Implementation Plan
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | July 2024

3

Technical Rationale and
Justification for TPL-008-1

Project 2023-07 Transmission Planning
Performance Requirements for Extreme
Weather
July 2024

RELIABILITY | RESILIENCE | SECURITY

NERC | Report Title | Report Date
I

Table of Contents
Preface ........................................................................................................................................................................... iii
Introduction ................................................................................................................................................................... iv
Defined Terms ................................................................................................................................................................. 5
TPL-008-1 Standard ......................................................................................................................................................... 6
Requirement R1 .............................................................................................................................................................. 7
Requirement R2 .............................................................................................................................................................. 8
Requirement R3 .............................................................................................................................................................. 9
Requirement R4 ............................................................................................................................................................ 10
Requirement R5 ............................................................................................................................................................ 11
Requirement R6 ............................................................................................................................................................ 12
Requirement R7 ............................................................................................................................................................ 13
Requirement R8 ............................................................................................................................................................ 15
Requirement R9 ............................................................................................................................................................ 17
Requirement R10 .......................................................................................................................................................... 18
Requirement R11 .......................................................................................................................................................... 19

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
ii

Preface
Electricity is a key component of the fabric of modern society and the Electric Reliability Organization (ERO) Enterprise
serves to strengthen that fabric. The vision for the ERO Enterprise, which is comprised of NERC and the six Regional
Entities, is a highly reliable, resilient, and secure North American bulk power system (BPS). Our mission is to assure
the effective and efficient reduction of risks to the reliability and security of the grid.
Reliability | Resilience | Security
Because nearly 400 million citizens in North America are counting on us
The North American BPS is made up of six Regional Entities as shown on the map and in the corresponding table
below. The multicolored area denotes overlap as some load-serving entities participate in one Regional Entity while
associated Transmission Owners/Operators participate in another.

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

Texas RE

Texas Reliability Entity

WECC

WECC

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
iii

Introduction
This document explains the technical rationale and justification for the proposed Reliability Standard TPL-008-1. It
provides stakeholders and the ERO Enterprise with an understanding of the technology and technical requirements
in the Reliability Standard. This Technical Rationale and Justification for TPL-008-1 is not a Reliability Standard and
should not be considered mandatory and enforceable.

Background

On June 15, 2023, FERC issued FERC Order No. 896 that acknowledges the “challenges associated with planning for
extreme heat and cold weather events, particularly those that occur during periods when the Bulk-Power System
must meet unexpectedly high demand. Extreme heat and cold weather events have occurred with greater frequency
in recent years and are projected to occur with even greater frequency in the future. These events have shown that
load shed during extreme temperatures result in unacceptable risk to life and have extreme economic impact. As
such, the impact of concurrent failures of Bulk-Power System generation and transmission equipment and the
potential for cascading outages that may be caused by extreme heat and cold weather events should be studied and
corrective actions should be identified and implemented.” 1
Therefore, the Commission directed in FERC Order No. 896 to develop a new or modified Reliability Standard to
address a lack of long-term planning requirement(s) for extreme heat and cold weather events. Specifically, FERC
directed NERC to develop modifications to Reliability Standard TPL-001-5.1 or a new Reliability Standard, to require
the following: (1) development of benchmark planning cases based on major prior extreme heat and cold weather
events and/or meteorological projections; (2) planning for extreme heat and cold weather events using steady state
and transient stability analyses expanded to cover a range of extreme weather scenarios including the expected
resource mix's availability during extreme heat and cold weather conditions, and including the wide-area impacts of
extreme heat and cold weather; and (3) development of corrective action plans that mitigate any instances where
performance requirements for extreme heat and cold weather events are not met.

1

N. Am. Elec. Reliability Corp., 183 FERC ¶ 61,191 (2023) (FERC Order), Final Rule. eLibrary | File List (ferc.gov)
NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
iv

Defined Terms
The Standard Drafting Team (SDT) defined one term to be added to the NERC Glossary of Terms to make the
requirements easier to read and understand.
Extreme Temperature Assessment
Documented evaluation of future Bulk Electric System performance for extreme heat and extreme cold
temperature benchmark events.
The definition of Extreme Temperature Assessment was developed by the SDT to limit wordiness throughout the
requirements.

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
5

TPL-008-1 Standard
The FERC Order No. 896 directed NERC to submit a new Reliability Standard or modifications to Reliability Standard
TPL-001-5.1 to address the concerns pertaining to transmission system planning for extreme heat and cold weather
events that impact the Reliable Operation of the Bulk-Power System.
The SDT developed TPL-008-1 to address the FERC directive and determined that a new Reliability Standard was the
cleanest way to address all directives versus modifying Reliability Standard TPL-001-5.1. While the TPL-008-1
standard pulls in similar requirements, this allows industry to have one standard that focuses on extreme heat and
extreme cold weather benchmark planning analysis requirements.

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
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Requirement R1
Requirement R1 was drafted to allow Planning Coordinator(s) (PC) and its Transmission Planner(s) (TP) within the
PC’s footprint to coordinate each entity’s individual and joint responsibilities when completing the Extreme
Temperature Assessment. The purpose of this requirement is to have the PC and its TPs identify their individual and
joint responsibilities for the following activities: selecting the extreme heat and cold benchmark temperature
events, developing and maintaining modeling data, having acceptable criteria, identifying Contingencies,
performing steady state and transient stability analyses, developing Corrective Action Plans (CAPs) for Table 1 P0
and P1 Contingencies, evaluating and documenting possible actions for Table 1 P2, P4, and P7 Contingencies, and
providing study results to any functional entity who have a reliability related need.

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
7

Requirement R2
Requirement R2 describes the need to select foundational weather data necessary for the creation of benchmark
planning cases. Specifically, extreme hot and cold temperatures experienced during benchmark events are assumed
to be outside the ranges used as the basis of planning cases studied under Reliability Standard TPL-001-5.1. Since
temperature levels and associated weather conditions affect load levels, generation performance, and transfer levels,
the selection of benchmark events is critical to ensuring the Extreme Temperature Assessment appropriately
evaluates probable System conditions.
The SDT determined that the extreme heat and extreme cold temperatures selected must have a verified statistical
basis based on weather data from credible sources. However, because there are many factors to consider in selecting
benchmark events (e.g., temperature magnitude, duration of the event, geographical area impacted, etc.) the SDT is
not in a position to provide that statistical basis or determine the appropriateness of any specific event. Therefore,
to ensure consistency across regions, it is necessary for the ERO to have the responsibility for determining the
suitability of benchmark events to represent probable future conditions. The ERO will maintain a library of benchmark
events and develop a process to incorporate additional events proposed by responsible entities. Responsible entities
will then have access to vetted benchmark weather data in a format that can be incorporated into benchmark
planning cases.
Since any region can experience temperatures that are higher or lower than normal, each responsible entity must
select at least one case that includes hotter temperature assumptions and one case that includes colder temperature
assumptions. While it is understood that, for example, one region may typically experience hotter summers and
milder winters than another region, both a hotter than average summer and a colder than average winter could result
in reliability concerns. Therefore, the requirement is for at least one case specific to extreme heat and at least one
case specific to extreme cold conditions to be studied for the Extreme Temperature Assessment.

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
8

Requirement R3
Requirement R3 aligns with directives in FERC Order 896, emphasizing the importance of coordinating the
development of benchmark planning cases amongst impacted responsible entities, where the scope of extreme
temperature event studies will likely cover large geographical areas exceeding smaller individual planning areas.
Rather than attempting to define study boundaries, the SDT instead focused on developing language that ensures
Planning Coordinators establish a process that ensures coordination of temperature-dependent variables with other
affected entities based upon the selected benchmark temperature events.
NERC already defines “Wide Area” as “The entire Reliability Coordinator Area as well as the critical flow and status
information from adjacent Reliability Coordinator Areas as determined by detailed system studies to allow the
calculation of Interconnected Reliability Operating Limits.” Reliability Coordinator Areas can be geographically very
large – for example the Reliability Coordinator West (RCW) region extends from the Pacific Northwest to the southern
borders of California and Arizona. Thus, defining coordination requirements based on these boundaries may not
accurately capture weather events and system impacts at a sufficiently granular level. In addition, it is recognized
that electrical boundaries such as those defining the Eastern/Western/ERCOT interconnections limit the potential for
events in one area to affect reliability in another.
The SDT considered comments from the industry expressing concerns regarding the necessity to coordinate among
all impacted Planning Coordinators in developing benchmark planning cases for various extreme temperature
benchmark temperature events. Recognizing that coordination among all impacted Planning Coordinators may not
be necessary to ensure reliability within an individual planning area, the SDT revised Requirement R3 to require each
Planning Coordinator to develop and implement a process for coordinating the development of benchmark planning
cases among adjacent impacted Planning Coordinator(s), Transmission Planner(s), and other designated study
entities, within the same Interconnection. The SDT believes this change balances the need to ensure the planning
cases capture impacts to/from entities affected by the same benchmark weather event, while recognizing that
reliability will not be impacted by system changes far removed from the individual planning area.

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
9

Requirement R4
The SDT revised Requirement R4 to require the responsible entity to use data consistent with Reliability Standard
MOD-032 for developing and maintaining benchmark planning cases that include seasonal and temperature
dependent adjustment for Load, generation, Transmission and transfers representing System conditions based on
selected benchmark events. This aligns with directives in FERC Order 896, paragraph 30, emphasizing the
requirement of developing both benchmark planning cases and sensitivity study cases. Requirement R4 is consistent
with how Reliability Standard TPL-001-5.1 cross-references Reliability Standard MOD-032, which establishes
consistent modeling data requirements and reporting procedures for the development of planning horizon cases
necessary to support analysis of the reliability of the interconnected System.
As per Order 896, paragraph 94, it is clarified that resource adequacy benchmarks are not within the scope of TPL008-1. The intent of the standard is to evaluate benchmark events where sufficient generation is available to supply
load. However, under an extreme heat or extreme cold temperature condition, there may be instances where the
benchmark planning cases and/or sensitivity cases may not have sufficient available generation to supply the load. In
these scenarios, it may be acceptable for the responsible entity to revise the model to reduce the projected load, or
include reasonable projections of future resources, to achieve a solution for the benchmark planning case and
evaluate future Bulk Electric System performance for extreme temperature events.

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
10

Requirement R5
Requirement R5 was drafted to require each responsible entity to set the criteria needed for limits that will be used
to evaluate the steady-state voltage and thermal results from the Extreme Temperature Assessment. The
establishment of these criteria allows auditors to compare the results of the assessment with the established criteria.

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
11

Requirement R6
Requirement R6 was drafted to require the responsible entity to have the criteria or methodology used in evaluating
the Extreme Temperature Assessment analysis to identify instability, uncontrolled separation, or Cascading within an
Interconnection. Adequate and thorough criteria should be built into the Extreme Temperature Assessment to help
identify instability, uncontrolled separation, and Cascading conditions. The establishment of these criteria allows
auditors to compare the results of the assessment with the established criteria.

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
12

Requirement R7
This requirement addresses directives in FERC Order No. 896 to define a set of Contingencies that responsible entities
will be required to consider when conducting wide-area studies of extreme heat and cold weather events. FERC’s
preference to rely on established Contingency definitions, “[w]e believe that it is necessary to establish a set of
common contingencies for all responsible entities to analyze. Required contingencies, such as those listed in Table 1
of Reliability Standard TPL-001-5.1 (i.e., category P1 through P7), establish common planning events that set the
starting point for transmission system planning assessments,” was also considered by the SDT. It is necessary to
establish a set of common Contingencies for all responsible entities to analyze. Requiring the study of predefined
Contingencies, such as those listed in Table 1, will ensure a level of uniformity across planning regions, considering
that extreme heat and cold weather events often exceed the geographic boundaries of most existing planning
footprints. Defining the Contingencies in Table 1 consistently with Table 1 of Reliability Standard TPL-001-5.1 meets
FERC’s preference for commonality.
If feasible, all Contingencies or Planning Events listed in Table 1 should be considered for evaluation by the
responsible entity; however, the language affords flexibility in identifying the most appropriate Contingencies. As
such, the responsible entity should implement a method and establish sufficient supporting rationale to ensure
Contingencies that are expected to produce more severe System impacts within its planning area are adequately
identified. It is noted that since the benchmark planning cases are developed from the extreme temperature
benchmark events, they already represent extreme System conditions and thus not all Contingencies from Reliability
Standard TPL-001-5.1 Table 1 are included in the TPL-008-1 Table 1 for assessment. The Events included in TPL-0081 Table 1 represent the more likely Contingencies to occur.
The SDT finds it reasonable to exclude P3, P5 and P6 Contingencies from the Extreme Temperature Assessment. The
following discusses the rationale for excluding these Contingencies for TPL-008-1:
1. Excluding P3 and P6 Contingencies:
Part of the decision stems from the complexity of P3 and P6, which involve multiple element outages
triggered by multiple Contingencies, with System adjustments allowed between them. Consequently, the
occurrence likelihood of P3 and P6 could be even lower compared to P2, P4, and P7 Contingencies. Moreover,
aligning with the directives set forth in FERC Order 896, which emphasizes the importance of incorporating
derated generation, transmission capacity, and the availability of generation and transmission in the
development of benchmark planning cases, it becomes imperative for responsible entities to consider
potential concurrent or correlated generation and transmission outages and/or derates within relevant
benchmark planning cases. This ensures that the benchmark planning case accurately reflects System
conditions under extreme temperatures, with generation and transmission derates and/or outages already
factored. Therefore, the SDT believes excluding P3 and P6 is justified, as generation and transmission derates
and/or outages are already accounted for within the benchmark planning cases.
2. Excluding P5 Contingencies:
After consideration of comments were received, the SDT removed P5 Contingency (Delayed Fault Clearing
due to failure of non-redundant component of a Protection System). This is because while some categories
of Contingencies may be assessed in a straightforward approach, category P5 events often require a
significant level of engineering analysis (including protection and/or control analysis). These analyses are
sensitive to the System topology and expected dispatch. As the planning benchmark cases are developed for
TPL-008-1 that represent System conditions that are different than the typical summer or winter peak
conditions, the development of category P5 events is expected to be a significant burden. Since these events
only require evaluations of possible mitigations (and not CAPs), violations resulting from these events are
NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
13

unlikely to result in significant transmission System investment. Furthermore, any violations resulting from
category P5 events may be mitigated by eliminating and addressing the single point of failure included in the
event definition. Thus, the evaluation of possible actions is unlikely to result in further insight beyond the
general reliability improvements associated with eliminating single points of failure.
Some, but not all, items to consider when developing the rationale for selecting Contingencies are:
• Past studies,
• Subject matter expert knowledge of the responsible entity’s System (to be supplemented with data or
analysis), and
• Historical data from past operating events.

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
14

Requirement R8
Requirement R8 was drafted to provide clarity on the following:
1. Frequency of the Extreme Temperature Assessment (Assessment):
Due to significant level of data collection and coordination between the Planning Coordinator(s) and
Transmission Planner(s) for the potential wide-area extreme cold or extreme heat benchmark events, as
well as the need to document the assumptions and study results, the SDT opined that performing and
completing of the Assessment once every five calendar years is a reasonable timeframe to allow
responsible entities to coordinate, prepare, perform and document the Assessment study results. To the
extent that responsible entities want to perform more than one set of Assessment for an extreme heat and
extreme cold benchmark event, they can do so, but the minimum requirement is once every five calendar
years to perform and complete one set of Assessment.
2. What planning study cases are required?
The Requirement R8 includes the following minimum number of assessments to complete the Extreme
Temperature Assessment and address FERC 896 directives per paragraph 111 that “direct NERC to require
in the proposed new or modified Reliability Standard that responsible entities perform both steady state
and transient stability (dynamic) analyses in the extreme heat and cold weather planning studies”. In
addition, Requirement R8 also addresses FERC 896 directives per paragraph 124 that “require the use of
sensitivity cases to demonstrate the impact of changes to the assumptions used in the benchmark planning
case”. Requirement R8 also addresses FERC directives per paragraph 124 that sensitivity cases “should
consider including conditions that vary with temperature such as load, generation, and system transfers.”
Since the benchmark planning case(s) already include System conditions under extreme heat or extreme
cold events, the sensitivity analysis is to include, at a minimum, changes to one of the assumptions in
generation, loads or transfers. Since the minimum requirement includes changes to one of these
conditions, the PCs and the TPs can include further sensitivity assessments to change more conditions if
they choose to do so.
The following provides the minimum number of assessments required to complete the Extreme
Temperature Assessment for the benchmark planning cases, as well as for sensitivity assessments.
Type of Extreme
Temperature
Assessment

Extreme Cold Temperature
Event

Extreme Heat
Temperature Event

Total

Benchmark Planning
Case Analysis

A minimum of one extreme
cold benchmark planning
case assessment

A minimum of one extreme
heat benchmark planning
case assessment

Total Minimum: Two
benchmark planning
case assessments

Sensitivity Analysis

A minimum of one
sensitivity study case for
one of the following:

A minimum of one
sensitivity study case for
one of the following:

Total Minimum: Two
sensitivity cases
analysis

1. Changes in generation
availability, or

1. Changes in generation
availability, or

2. Changes in load level
(real and reactive), or

2. Changes in load level
(real and reactive), or

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
15

Type of Extreme
Temperature
Assessment

Extreme Cold Temperature
Event
3. Changes in transfer
level

Extreme Heat
Temperature Event

Total

3. Changes in transfer
level

Total

A minimum total of
four assessments to
complete the
Extreme
Temperature
Assessment

3. What are the types of power flow related analyses?
There are two types of power flow related analyses: a steady-state and a stability analysis that are applied
for the minimum of four planning study cases as identified in the above table. This requirement is to satisfy
FERC Order 896 directive paragraph 111.

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
16

Requirement R9
FERC Order 896 identifies a deficiency in the existing Reliability Standard TPL-001-5.1 where “planning coordinators
and transmission planners are required to evaluate possible actions to reduce the likelihood or mitigate the
consequences of extreme temperature events but are not obligated to develop corrective action plans” (¶139).
Given potential severe consequences of extreme cold and extreme heat events, FERC Order 896 raises the bar and
“directs NERC to require in the new or modified Reliability Standard the development of extreme weather corrective
action plans for specified instances when performance standards are not met” (¶152).
Due to higher likelihood of P0 and P1 planning events, performance requirements for P0 and P1 Contingencies are
held to a higher performance standard, and Corrective Action Plans (CAPs) are required to address performance
deficiencies for P0 and P1 Contingencies in the Extreme Temperature Assessments.
Furthermore, having a CAP requirement for P0 and P1 contingencies aligns with ensuring resilience during future
extreme cold and extreme heat events, when the transmission System is required to be P1-secure (using contingency
analysis, voltage stability and transient stability).
Given that a P0 planning event represents a continuous System condition without any system disturbances, the SDT
opined that load shedding should not be considered as a CAP. However, the SDT has determined that load curtailment
may be considered for a P1 Contingency as a CAP where load shed is allowed to prevent system-wide failures and
ensuring the continued operation of essential services under a critical P1 Contingency in the extreme heat and cold
temperature events. The SDT also emphasizes that other alternative solutions, other than firm load curtailment, are
evaluated in higher priorities. In the event that firm Load shed is included in the CAP for a P1 contingency, the
responsible entity shall document the alternative(s) considered, as mentioned in Requirement R9, and notify the
applicable regulatory authorities or governing bodies responsible for retail electric service issues.

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
17

Requirement R10
The requirement for responsible entities to assess and document possible actions designed to reduce the likelihood
or mitigate the consequences of System instability, uncontrolled separation, or Cascading failures during P2, P4, and
P7 Contingencies is in response to directives outlined in FERC Order 896.
The P2, P4, and P7 Contingencies involve multiple element outages resulting from a single event, making them
relatively less likely to occur compared to P0 and P1 Contingencies but potentially causing more severe system
impacts. Considering both the likelihood of these Contingencies and the fact that the Extreme Temperature
Assessment already addresses low-probability System conditions, the SDT determined that no Corrective Action Plan
is required for P2, P4, and P7 Contingencies. However, due to their potential severity resulting from singleContingency multiple element outages, the SDT believes it is appropriate for responsible entities to at least evaluate
and document possible mitigation actions to reduce the likelihood or mitigate the consequences and adverse
impacts. The biggest benefit from the evaluation and documentation of the mitigating actions is it allows an entity to
see where major problems exist that they may need to be addressed; and, if a project shows up on enough issues, it
may encourage a fix to be implemented without it being strictly called for from the standard. Not requiring CAPs for
these contingencies but requiring the evaluation is a compromise from having CAPs for all studied issues.

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
18

Requirement R11
The requirement for responsible entities to share Extreme Temperature Assessment results aligns with directives in
FERC Order 896, emphasizing coordination and sharing of study findings. It ensures collaboration among stakeholders
and timely dissemination of critical information to entities with reliability-related needs. This fosters a collective
understanding of reliability concerns identified in wide-area studies, thereby enhancing overall grid reliability.

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
19

Unofficial Comment Form

Project 2023-07 Transmission Planning Performance Requirements for
Extreme Weather
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on draft two of TPL-008-1 – Transmission System Planning Performance
Requirements for Extreme Temperature Events by 8 p.m. Eastern, Thursday, August 22, 2024.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Senior Standards
Developer, Jordan Mallory (via email), or at 470-479-7538.
Background Information

On June 15, 2023, FERC issued FERC Order No. 896 that acknowledges the “challenges associated with
planning for extreme heat and cold weather events, particularly those that occur during periods when the
Bulk-Power System must meet unexpectedly high demand. Extreme heat and cold weather events have
occurred with greater frequency in recent years, and are projected to occur with even greater frequency
in the future. These events have shown that load shed during extreme temperature result in unacceptable
risk to life and have extreme economic impact. As such, the impact of concurrent failures of Bulk-Power
System generation and transmission equipment and the potential for cascading outages that may be
caused by extreme heat and cold weather events should be studied and corrective actions should be
identified and implemented.” 1
Therefore, the Commission directed in FERC Order No. 896 to develop a new or modified Reliability
Standard to address a lack of long-term planning requirement(s) for extreme heat and cold weather
events. Specifically, FERC directed NERC to develop modifications to Reliability Standard TPL-001-5.1 or a
new Reliability Standard, to require the following: (1) development of benchmark planning cases based on
major prior extreme heat and cold weather events and/or meteorological projections; (2) planning for
extreme heat and cold weather events using steady state and transient stability analyses expanded to
cover a range of extreme weather scenarios including the expected resource mix's availability during
extreme heat and cold weather conditions, and including the wide-area impacts of extreme heat and cold
weather; and (3) development of corrective action plans that mitigate any instances where performance
requirements for extreme heat and cold weather events are not met.

1

N. Am. Elec. Reliability Corp., 183 FERC ¶ 61,191 (2023) (FERC Order), Final Rule. eLibrary | File List (ferc.gov)

RELIABILITY | RESILIENCE | SECURITY

Questions

1. The drafting team (DT) updated the Requirements in chronological order. Do you agree with the
proposed TPL-008-1 Reliability Standard Requirement layout? If you do not agree, please provide
your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
2. The DT updated Requirements R1 – R2 based on comments received. Do you agree with the
updated proposed TPL-008-1 Reliability Standard Requirements R1-R2? If you do not agree, please
provide your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
3. The DT updated Requirements R3 – R5 based on comments received. Do you agree with the
updated proposed TPL-008-1 Reliability Standard Requirements R3-R5? If you do not agree, please
provide your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
4. The DT updated Requirements R6 – R8 based on comments received. Do you agree with the
updated proposed TPL-008-1 Reliability Standard Requirements R6-R8? If you do not agree, please
provide your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
5. The DT updated Requirement R9 based on comments received. Do you agree with the updated
proposed TPL-008-1 Reliability Standard Requirement R9? If you do not agree, please provide your
recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:

Unofficial Comment Form
Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather | July 2024

6. The DT updated Requirement R10 based on comments received. Do you agree with the updated
proposed TPL-008-1 Reliability Standard Requirement R10? If you do not agree, please provide
your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
7. The DT split out Table 1 into parts for better readability. Do you agree with the updated layout of
Table 1? If you do not agree, please provide your recommendation and technical justification.
Yes
No
Comments:
8. The DT believes proposed modifications in TPL-008-1 provide entities with flexibility to meet the
reliability objectives in a cost-effective manner. Do you agree? If you do not agree, or if you agree
but have suggestions for improvement to enable more cost-effective approaches, please provide
your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
9. Provide any additional comments for the standard drafting team to consider, including the
provided technical rationale document, if desired.
Comments:

Unofficial Comment Form
Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather | July 2024

Violation Risk Factor and Violation Severity Level
Justifications

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
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 2023-07 Transmission System Planning Performance Requirements for Extreme Weather. 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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

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
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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

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 Justifications for TPL-008-1, Requirement R1
Proposed VRF

Lower

NERC VRF Discussion

A VRF of Lower is appropriate due to the fact that the Planning Coordinators, in conjunction with its
Transmission Planner(s) will determine joint responsibilities for requirements throughout TPL-008-1.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

5

VSLs for TPL-008-1, Requirement R1
Lower
N/A

Moderate
N/A

High
N/A

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

Severe
The Planning Coordinator, in
conjunction with its Transmission
Planner(s), failed to determine and
identify individual and joint
responsibilities for completing the
Extreme Temperature Assessment.

6

VSL Justifications for TPL-008-1, Requirement R1
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the Planning Coordinator and Transmission Planner to determine
who completes the responsibilities throughout TPL-008-1. The responsibilities documentation will either be
developed or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

7

VRF Justifications for TPL-008-1, Requirement R2
Proposed VRF

High

NERC VRF Discussion

A VRF of high is appropriate due to the fact that selecting a benchmark event to perform an extreme
temperature assessment can affect the grid based on planning analysis for future events.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

8

VSLs for TPL-008-1, Requirement R2
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity did not
select at least one extreme heat
benchmark event or extreme cold
benchmark temperature event
from the ERO approved benchmark
library for performing the Extreme
Temperature Assessment.

The responsible entity did not
select an extreme heat benchmark
event and extreme cold benchmark
temperature event from the ERO
approved benchmark library for
performing the Extreme
Temperature Assessment.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

9

VSL Justifications for TPL-008-1, Requirement R2
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

This VSL has been assigned as a binary due to the benchmark event needing to be selected for benchmark
planning cases to be completed. You either select a benchmark event or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

10

VRF Justifications for TPL-008-1, Requirement R3
Proposed VRF

High

NERC VRF Discussion

A VRF of high is appropriate due to the fact that it is important to develop and maintain System models within
an entity’s planning area for performing Extreme Temperature Assessments. Connecting to MOD-032 to provide
important data needed to assist entities with System models is also important for accurate information to be
used.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

11

VSLs for TPL-008-1, Requirement R3
Lower
N/A

Moderate
N/A

High
N/A

Severe
The Planning Coordinator did not
develop or implement a process for
coordinating the development of
benchmark planning cases among
impacted adjacent Planning
Coordinator(s), Transmission
Planner(s), and other designated
study entities, within the same
Interconnection.
OR
The Planning Coordinator
developed and implemented a
process for coordinating the
development of benchmark
planning cases among impacted
adjacent Planning Coordinator(s),
Transmission Planner(s), and other
designated study entities within
the same Interconnection, but this
process did not modify the
benchmark planning cases to
include seasonal and temperature
dependent adjustments load,
generation, Transmission, and
transfers.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

12

VSL Justifications for TPL-008-1, Requirement R3
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either develops and maintains the System
models within its planning area or it does not develop and maintain the System models within its planning area.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

13

VRF Justifications for TPL-008-1, Requirement R4
Proposed VRF

Medium

NERC VRF Discussion

The VRF of Medium is appropriate because it could directly affect the electrical state or capability of the BPS if
coordination is not completed for benchmark planning cases and sensitivity cases for the Extreme Temperature
Assessment results.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

14

VSLs for TPL-008-1, Requirement R4
Lower
N/A

Moderate
N/A

High
N/A

Severe
The responsible entity did not
develop or maintain benchmark
planning cases or sensitivity cases
for performing the Extreme
Temperature Assessment.
OR
The responsible entity developed
and maintained benchmark
planning cases or sensitivity cases
for performing the Extreme
Temperature Assessment but did
not use data consistent with that
provided in accordance with the
MOD-032 standard.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

15

VSL Justifications for TPL-008-1, Requirement R4
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the Planning Coordinator to develop and implement a process for
coordinating the development of benchmark planning cases. The benchmark planning cases will either be
developed and implemented or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

16

VRF Justifications for TPL-008-1, Requirement R5
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate due to the importance of having criteria for acceptable System steady state voltage
limits of post-Contingency voltage deviations for performing Extreme Temperature Assessments.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

17

VSLs for TPL-008-1, Requirement R5
Lower
N/A

Moderate
N/A

High
N/A

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

Severe
The responsible entity, as
determined in Requirement R1, did
not have criteria for acceptable
System steady state voltage limits,
post-Contingency voltage
deviations, and applicable Facility
Ratings for performing Extreme
Temperature Assessment.

18

VSL Justifications for TPL-008-1, Requirement R5
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either having acceptable criteria for System
steady state voltage limits and post-contingency voltage deviations or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

19

VRF Justifications for TPL-008-1, Requirement R6
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate due to the importance of defining and documenting the criteria or methodology for
System instability, uncontrolled separation, or Cascading.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

20

VSLs for TPL-008-1, Requirement R6
Lower
N/A

Moderate
N/A

High
N/A

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

Severe
The responsible entity failed to
define and document, the criteria
or methodology used in the
analysis to identify System
instability, uncontrolled separation,
or Cascading within an
Interconnection.

21

VSL Justifications for TPL-008-1, Requirement R6
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

22

VRF Justifications for TPL-008-1, Requirement R7
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate for this requirement. Identifying Contingencies for performing Extreme
Temperature Assessments for each of the event categories in Table 1 can directly impact the BES.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

23

VSLs for TPL-008-1, Requirement R7
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity, as
determined in Requirement R1,
identified Contingencies for
performing Extreme Temperature
Assessment for each of the
planning events in Table 1 that are
expected to produce more severe
System impacts within its planning
area, but did not include the
rationale for those Contingencies
selected for evaluation as
supporting documentation.

The responsible entity, as
determined in Requirement R1, did
not identify Contingencies for
performing Extreme Temperature
Assessment for each of the
planning events in Table 1 that are
expected to produce more severe
System impacts within its planning
area.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

24

VSL Justifications for TPL-008-1, Requirement R7
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

25

VRF Justifications for TPL-008-1, Requirement R8
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate due to the importance of performing an Extreme Temperature Assessment every 5
years.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

26

VSLs for TPL-008-1, Requirement R8
Lower
The responsible entity, as
determined in Requirement R1,
completed an Extreme
Temperature Assessment, but it
was performed less than or equal
to six months late.

Moderate

High

The responsible entity, as
determined in Requirement R1,
completed an Extreme
Temperature Assessment, but it
was performed more than six
months but less than or equal to 12
months late.

The responsible entity, as
determined in Requirement R1,
completed an Extreme
Temperature Assessment, but it
was performed more than 12
months but less than or equal to 18
months late.

Severe
The responsible entity, as
determined in Requirement R1,
performed an Extreme
Temperature Assessment, but it
was more than 18 months late.
OR
The responsible entity, as
determined in Requirement R1, did
not perform an Extreme
Temperature Assessment.
OR
The responsible entity, as
determined in Requirement R1,
performed an Extreme
Temperature Assessment, but it
was missing one or more of the
required elements in Requirement
R8.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

27

VSL Justifications for TPL-008-1, Requirement R8
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

28

VRF Justifications for TPL-008-1, Requirement R9
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate for this requirement. Developing a Corrective Action Plan is important to the BES as
it assists entities when Systems are unable to meet performance requirements.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

29

VSLs for TPL-008-1, Requirement R9
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity, as
determined in Requirement R1,
developed a Corrective Action Plan
meeting each of the elements in
Requirement R9, but failed to make
their Corrective Action Plan
available to, or solicit feedback
from, applicable regulatory
authorities or governing bodies
responsible for retail electric
service issues.

The responsible entity, as
determined in Requirement R1,
failed to develop a Corrective
Action Plan meeting each of the
elements of Requirement R9 when
the benchmark planning case study
results indicate the System is
unable to meet performance
requirements for the Table 1 P0 or
P1 Contingencies.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

30

VSL Justifications for TPL-008-1, Requirement R9
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either having acceptable criteria for System
steady state voltage limits and post-contingency voltage deviations or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

31

VRF Justifications for TPL-008-1, Requirement R10
Proposed VRF

Lower

NERC VRF Discussion

A VRF of lower has been assigned to Requirement R10. Documenting possible actions to reduce the likelihood
or mitigate the consequences and adverse impacts are administrative in nature.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

32

VSLs for TPL-008-1, Requirement R10
Lower
N/A

Moderate
N/A

High
N/A

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

Severe
Each responsible entity, as
determined in Requirement R1,
failed to evaluate and document
possible actions, mitigate the
consequences, and adverse
impacts when the benchmark
planning case study results indicate
the System could result in
instability, uncontrolled separation,
or Cascading for the Table 1 P2, P4,
and P7 Contingencies.

33

VSL Justifications for TPL-008-1, Requirement R10
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the fact that the responsible entity will either have evaluated and
documented possible actions to mitigate adverse impacts.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

34

VRF Justifications for TPL-008-1, Requirement R11
Proposed VRF

Medium

NERC VRF Discussion

The VRF of Medium is appropriate because it could directly affect the electrical state or capability of the BES if
entities are not aware of the results from its Extreme Temperature Assessment results.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

35

VSLs for TPL-008-1, Requirement R11
Lower

Moderate

High

Severe

The responsible entity, as
determined in Requirement R1,
distributed its Extreme
Temperature Assessment results to
functional entities having a
reliability related need who
requested the information in
writing, but it was more than 60
days but less than or equal to 80
days following the request.

The responsible entity, as
determined in Requirement R1,
distributed its Extreme
Temperature Assessment results to
functional entities having a
reliability related need who
requested the information in
writing, but it was more than 80
days but less than or equal to 100
days following the request.

The responsible entity, as
determined in Requirement R1,
distributed its Extreme
Temperature Assessment results to
functional entities having a
reliability related need who
requested the information in
writing, but it was more than 100
days but less than or equal to 120
days following the request.

The responsible entity, as
determined in Requirement R1,
distributed its Extreme
Temperature Assessment results to
functional entities having a
reliability related need who
requested the information in
writing, but it was more than 120
days following the request.
OR
The responsible entity, as
determined in Requirement R1, did
not distribute its Extreme
Temperature Assessment results to
functional entities having a
reliability related need who
requested the information in
writing.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

36

VSL Justifications for TPL-008-1, Requirement R11
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | July 2024

37

Consideration of FERC Order 896 Directives

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
July 2024
On June 15, 2023, FERC issued a Final Rule, Order No. 896, directing NERC to develop a new or modified Reliability Standard to address a lack
of a long-term planning requirement(s) for extreme heat and cold weather events. Specifically, FERC directed NERC to develop modifications to
Reliability Standard TPL-001-5.1 or to develop a new Reliability Standard to require the following: (1) development of benchmark planning
cases based on major prior extreme heat and cold weather events and/or meteorological projections; (2) planning for extreme heat and cold
weather events using steady state and transient stability analyses expanded to cover a range of extreme weather scenarios including the
expected resource mix's availability during extreme heat and cold weather conditions, and including the wide-area impacts of extreme heat
and cold weather; and (3) development of corrective action plans that mitigate any instances where performance requirements for extreme
heat and cold weather events are not met. FERC directed NERC to submit a new or revised standard within 18 months, or by December 2024.
The below provides the directives from FERC Order 896 along with the drafting team’s consideration of the directives.

Directive Language

FERC Order 896 Directives

P35. “[W]e direct NERC to: (1) develop extreme heat and cold weather
benchmark events, and (2) require the development of benchmark
planning cases based on identified benchmark events.”
P36: “…As recommended by commenters, NERC should consider the
examples of approaches for defining benchmark events identified in the
NOPR (e.g., the use of projected frequency or probability distribution).
NERC may also consider other approaches that achieve the objectives
outlined in this final rule.”

Consideration of Directives

The ERO will work with respective subject matter experts, including climate
experts, the six regions, etc., and develop extreme heat and extreme cold
weather benchmark events. An ERO-maintained library will be created, and
all developed extreme heat and extreme cold weather benchmark events
will be retained. From this library, responsible entities will be able to
review and select the appropriate benchmark events to assist with the
development of its benchmark planning cases.
NERC, in consultation with climate data subject matter expert consultants
on the benchmark events, utilizes publicly available modeled data to
inform TPL-008-1 data library and potentially augment it with historical

RELIABILITY | RESILIENCE | SECURITY

Directive Language

FERC Order 896 Directives

Consideration of Directives

observations as needed. Further information on the benchmark events will
be posted by NERC in the July 2024 timeframe.
The drafting team developed requirements within TPL-008-1 to require
responsible entities to select one extreme heat benchmark event and
extreme cold benchmark event from the approved ERO library
(Requirement R2). After selecting its benchmark events, the responsible
entity is required to develop and implement a process for coordinating the
development of benchmark planning cases among the responsible entities
(Requirement R3) and to develop and maintain benchmark planning cases
and sensitivity cases (Requirement R4).

P38. “[I]n developing extreme heat and cold benchmark events, NERC shall
ensure that benchmark events reflect regional differences in climate and
weather patterns.”

NERC, in consultation with climate data subject matter expert consultants
on benchmark events, has utilized publicly available modeled data in the
last forty-three years (1980-2022), as well as more than eighty years of
projected hourly meteorology data from PNNL to ensure regional
differences in climate and weather patterns are reflected within the
developed benchmark events. Benchmark events are provided for eleven
regions in the continental United States and provinces in Canada.

P39. “We also direct NERC to include in the Reliability Standard the
framework and criteria that responsible entities shall use to develop from
the relevant benchmark event planning cases to represent potential
weather-related contingencies (e.g., concurrent/correlated generation and
transmission outages, derates) and expected future conditions of the
system such as changes in load, transfers, and generation resource mix,
and impacts on generators sensitive to extreme heat or cold, due to the
weather conditions indicated in the benchmark events. Developing such a
framework would provide a common design basis for responsible entities
to follow when creating benchmark planning cases. This would not only

The directive is addressed in proposed TPL-008-1 through Requirements
R3, R4, and R8.
Requirement R3 obligates the Planning Coordinator to develop and
implement a process to coordinate the development of the benchmark
planning cases. This process shall include seasonal and temperature
dependent adjustments for Load, generation, Transmission, and transfers
to represent the selected benchmark temperature events.

Consideration of FERC Order 896 Directives
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help establish a clear set of expectations for responsible entities to follow
when developing benchmark planning events, but also facilitate auditing
and enforcement of the Standard.”

P40. “We also direct NERC to ensure the reliability standard contains
appropriate mechanisms for ensuring the benchmark event reflects up-todate meteorological data.”

P50. “[W]e…direct NERC to require that transmission planning studies
under the new or revised Reliability Standard consider the wide-area
impacts of extreme heat and cold weather. We direct NERC to clearly
describe the process that an entity must use to define the wide-area
boundaries. While commenters provide various views in favor of both a
geographical approach and electrical approach to defining wide-area
boundaries, we do not adopt any one approach in this final rule…NERC
should consider the comments in this proceeding when developing a new
or modified reliability standard that considers the broad area impacts of
extreme heat and cold weather.”

Consideration of Directives

Requirement R4 obligates the responsible entity to develop and maintain
benchmark planning cases and sensitivity cases for performing the Extreme
Temperature Assessment which reflects System conditions from the
selected benchmark events.
Requirement R8 obligates the responsible entity to complete an Extreme
Temperature Assessment for one of the years in the Long-Term
Transmission Planning Horizon, for the benchmark planning cases, as well
as sensitivity cases which include changes to one of these conditions:
generation, real or reactive forecasted Load, or transfers.
The drafting team discussed a similar process to how BAL-003 gathers data.
It was determined that the ERO, with the assistance from NERC’s
consultant, is in the best situation to provide a review with the respective
subject matter experts, including climate experts, the six regions, etc., and
update the benchmark events to reflect up-to-date meteorological data
every five years via a NERC process document.
The Standard Drafting Team (SDT) reviewed all the extreme weather
events mentioned within the FERC Order 896. In addition, NERC in
consultation with its climate data subject matter experts, utilized publicly
available modeled data in the last forty-three years (1980-2022), as well as
more than eighty years of projected hourly meteorology data from PNNL to
develop the benchmark events for the ERO-maintained library. The
benchmark events are provided and shown in a wide-area for various
regions within the continental United States, as well as Canadian provinces.
The drafting team addressed this directive by developing Requirement R2
and Requirement R3. Requirement R2 requires entities to, “select at least
one extreme heat benchmark temperature event and at least one extreme
cold benchmark temperature event, from the benchmark library, approved
and maintained by the Electric Reliability Organization (ERO), for
completing the Extreme Temperature Assessment.”

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P58. “[W]e…direct NERC to develop benchmark events for extreme heat
and cold weather events through the Reliability Standards development
process.”

Consideration of Directives

Requirement R3 requires Planning Coordinators to “develop and
implement a process for coordinating the development of benchmark
planning cases, using the selected benchmark temperature events
identified in Requirement R2, among adjacent impacted Planning
Coordinator(s), Transmission Planner(s), and other designated study
entities, within an Interconnection. This process shall include seasonal and
temperature dependent adjustments for Load, generation, Transmission,
and transfers to represent the selected benchmark temperature events.”
It was determined that the ERO, with the assistance from NERC’s subject
matter expert consultants, is in the best position to develop and update
benchmark events through a fair and open process outside of the
traditional standard development process. Such a process would allow
maximum flexibility to update the benchmark events as climate conditions
change or new science emerges. The ERO will initially work with its
consultant, Telos Energy, to develop benchmark events for the first fiveyear assessment cycle. For the future Extreme Temperature Assessment
(ETA) cycles, NERC will work with respective subject matter experts,
including climate experts, the six regions, as well as its consultant, to
develop future benchmark events. These events will be uploaded to an ERO
library where responsible entities will then select their respective
benchmark events from the ERO library to develop the benchmark
planning cases.
Requirement R2 obligates the responsible entity to select one extreme
heat benchmark event and one extreme cold benchmark event from the
approved benchmark library, that is approved and maintained by the ERO,
for completing the Extreme Temperature Assessment.

P60. “[W]e…direct NERC to designate the type(s) of entities responsible for
developing benchmark planning cases and conducting wide-area studies

The drafting team discussed that the Transmission Planner (TP) and/or
Planning Coordinator (PC) would be the responsible entities to address TPL-

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under the new or modified Reliability Standard…benchmark planning cases
should be developed by registered entities such as large planning
coordinators, or groups of planning coordinators, with the capability of
planning on a regional scope.”
P61: “We believe the designated responsible entities should have certain
characteristics, including having a wide-area view of the Bulk-Power
System and the ability to conduct long-term planning studies across a wide
geographic area. The responsible entities should also have the planning
tools, expertise, processes, and procedures to develop benchmark planning
cases and analyze extreme weather events in the long-term planning
horizon.”
P62: “To comply with this directive, NERC may designate the tasks of
developing benchmark planning cases and conducting wide-area studies to
an existing functional entity or a group of functional entities (e.g., a group
of planning coordinators). NERC may also establish a new functional entity
registration to undertake these tasks. In the petition accompanying the
proposed Reliability Standard NERC should explain how the applicable
registered entity or entities meet the objectives outlined above.”

P72. “[W]e direct NERC to require functional entities to share with the
entities responsible for developing benchmark planning cases and
conducting wide-area studies the system information necessary to develop
benchmark planning cases and conduct wide-area studies. Further,
responsible entities must share the study results with affected transmission
operators, transmission owners, generator owners, and other functional
entities with a reliability need for the studies.”

Consideration of Directives

008-1 Requirements. Requirement R1 obligates both the TP and PC to
identify their individual and joint responsibilities.
The drafting team reviewed all the extreme weather events mentioned
within the FERC Order 896. In addition, NERC’s consultant, Telos Energy,
utilized publicly available modeled data in the last forty-three years (19802022), as well as more than eighty years of projected hourly meteorology
data from PNNL to develop the benchmark events for the ERO-maintained
library. The selected benchmark event will include the impacted wide-area
for the regions in the continental United States, as well as Canadian
provinces. Requirement R3 obligates each the responsible entity to develop
and implement a process for coordinating the development of benchmark
planning cases, using the selected benchmark temperature events
identified in Requirement R2, among adjacent impacted Planning
Coordinator(s), Transmission Planner(s), and other designated study
entities, within an Interconnection.
Requirement R4 obligates each responsible entity, as identified in
Requirement R1, to use the coordination process developed in accordance
with Requirement R3 and data consistent with that provided in accordance
with the MOD-032 standard, supplemented by other sources as needed, to
develop and maintain benchmark planning cases and sensitivity cases.
The directive is addressed in proposed TPL-008-1 through requirements R3,
R4 and R11.
Requirement R3 obligates each responsible entity to develop and
implement a process for coordinating the development of benchmark
planning cases, using the selected benchmark temperature events
identified in Requirement R2, among adjacent impacted Planning

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Consideration of Directives

Coordinator(s), Transmission Planner(s), and other designated study
entities, within an Interconnection.
Requirement R4 obligates each responsible entity, as identified in
Requirement R1, to use the coordination process developed in accordance
with Requirement R3 and data consistent with that provided in accordance
with the MOD-032 standard, supplemented by other sources as needed, to
develop and maintain benchmark planning cases and sensitivity cases.
Requirement R11 obligates each responsible entity, as identified in
Requirement R1, to provide its Extreme Temperature Assessment results
within 60 calendar days of a request to any functional entity that has a
reliability related need and submits a written request for the information.

P73. “Because in this final rule we direct NERC to determine the
responsible entities that will be developing benchmark planning cases and
conducting wide-area studies, it is possible that the selected responsible
entities under the new or modified Reliability Standard will not be able to
request and receive needed data pursuant to MOD-032-1, absent
modification to that Standard.”

The drafting team discussed and determined that data needed to address
the Extreme Temperature Assessment would still be appropriate to receive
through MOD-032. MOD-032 ensures an adequate means of data

collection for transmission planning and requires applicable
registered entities to provide steady-state, dynamic, and short circuit
modeling data to their transmission planner(s) and planning
coordinator(s). As outlined in R1 and Attachment 1 of MOD-032,
MOD-032 allows various data collection such as in-service status and
capability associated with demand, generation, and transmission
associated with various case types, scenarios, system operating
states, or conditions for the long-term planning horizon. MOD-032
also requires applicable registered entities to provide “other
information requested by the Planning Coordinator or Transmission
Planner necessary for modeling purposes” for each of the three
types of data required. Because the drafting team determined the

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P76: “[W]e…direct NERC to address the requirement for wide-area
coordination through the standards development process, giving due
consideration to relevant factors identified by commenters in this
proceeding.”

Consideration of Directives
responsible entities that will be developing benchmark planning
cases are limited to planning coordinators and transmission
planners, they will be able to request and receive needed data
pursuant to MOD-032. Thus, the drafting team believes that there is
no need to update MOD-032 because it allows planning coordinators
and transmission planners to request any specific data needed for
developing and maintaining benchmark planning cases required in
R4 of TPL-008-1.
The directive is addressed in proposed TPL-008-1 through Requirements
R1, R3, R4 and R8. Requirement R1 obligates the Planning Coordinator, in
conjunction with its Transmission Planners(s), to identify each entity’s
individual and joint responsibilities for completing the Extreme
Temperature Assessment. Requirement R3 obligates the Planning
Coordinator to develop and implement a process for coordinating the
development of benchmark planning cases among adjacent impacted
Planning Coordinator(s), Transmission Planner(s), and other designated
study entities, within an Interconnection. Requirement R4 obligates the
responsible entity, as identified in Requirement R1, to develop and
maintain benchmark planning cases and sensitivity cases in accordance
with data consistent with the MOD-032 standard. Requirement R8
obligates the responsible entity, as identified in Requirement R1, to
perform steady state and transient stability analyses of the benchmark
planning and sensitivity cases developed in Requirement R4.
The drafting team reviewed all the extreme weather events mentioned
within the FERC Order 896. For this project, the drafting team focused the
scope of Requirement R3 to require each Planning Coordinator to develop
and implement a process for coordinating the development of benchmark
planning cases, using the selected benchmark temperature events
identified in Requirement R2, among adjacent impacted Planning

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P77. “[W]e direct NERC to require in the new or modified Reliability
Standard that responsible entities share the results of their wide-area
studies with other registered entities such as transmission operators,
transmission owners, and generator owners that have a reliability related
need for the studies.”
P88. “[W]e direct NERC to require under the new or revised Reliability
Standard the study of concurrent/correlated generator and transmission
outages due to extreme heat and cold events in benchmark events as
described in more detail below.”

P111. “[W]e direct NERC to require in the proposed new or modified
Reliability Standard that responsible entities perform both steady state and
transient stability (dynamic) analyses in the extreme heat and cold weather
planning studies. In a steady state analysis, the system components are
modeled as either in-service or out-of-service and the result is a single
point-in-time snapshot of the system in a state of operating equilibrium. A
transient stability (dynamic) analysis examines the system from the start to
the end of a disturbance to determine if the system regains a state of
operating equilibrium. Performing both analyses ensures that the system
has been thoroughly assessed for instability, uncontrolled separation, and

Consideration of Directives

Coordinator(s), Transmission Planner(s), and other designated study
entities, within an Interconnection. However, future modifications may be
needed as extreme temperature events evolve that may result in the need
for wider area impact of coordination between PCs.
This directive is addressed in proposed TPL-008-1 Requirement R11.
Requirement R11 obligates each responsible entity to provide the widearea study results within 60 calendar days of a request to any functional
entity that has a reliability related need and has submitted a written
request for the information.
This directive is addressed in proposed TPL-008-1 through Requirement R4.
Per Requirement R4 Part 4.1, the responsible entity is obligated to develop
and maintain benchmark planning cases that include seasonal and
temperature dependent adjustments for Load, generation, Transmission,
and transfers to represent the System conditions of the selected
benchmark temperature events for one of the years in the Long-Term
Transmission Planning Horizon. Per Requirement R4 Part 4.2, the
responsible entity is obligated to develop and maintain sensitivity cases by
changing at least one of the following conditions in the benchmark
planning cases: generation, real and reactive forecasted Load, or transfers.
This directive is addressed in proposed TPL-008-1 through Requirement R8
and Table 1.
Requirement R8 requires the responsible entity to complete both steady
state and transient stability analyses and document the assumptions and
results.
Table 1 obligates each responsible entity to perform both steady state and
transient stability analyses and compare the study results against steady
state and stability performance requirements.

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cascading failures in both the steady state and the transient stability
realms.” (internal citations omitted).
P112. “[W]e direct NERC to define a set of contingencies that responsible
entities will be required to consider when conducting wide-area studies of
extreme heat and cold weather events under the new or modified
Reliability Standard. We believe that it is necessary to establish a set of
common contingencies for all responsible entities to analyze. Required
contingencies, such as those listed in Table 1 of Reliability Standard TPL001-5.1 (i.e., category P1 through P7), establish common planning events
that set the starting point for transmission system planning assessments.
Requiring the study of predefined contingencies will ensure a level of
uniformity across planning regions—a feature that will be necessary in the
new or revised Reliability Standard considering that extreme heat and cold
weather events often exceed the geographic boundaries of most existing
planning footprints.”
P113: “[T]he contingencies required in the new or revised Reliability
Standards should reflect the complexities of transmission system planning
studies for extreme heat and cold weather events.”
P116. “[W]e direct NERC to require in the new or modified Reliability
Standard that responsible entities model demand load response in their
extreme weather event planning area. As indicated by several
commenters, because demand load response is generally a mitigating
action that involves reducing distribution load during periods of stress to
stabilize the Bulk-Power System, its effect during an extreme weather
event should be modeled.”

Consideration of Directives

This directive is addressed in proposed TPL-008-1 through Requirement R7
and Table 1.
Requirement R7 requires the responsible entity to identify Contingencies
for completing the Extreme Temperature Assessment. The rationale for
those Contingencies selected for evaluation shall be available as supporting
information.
The planning events for each Contingency category in Table 1 of TPL-008-1
correspond to the well-established Contingencies defined in Reliability
Standard TPL-001-5.1. Table 1 also establishes common planning events
that set the starting point for transmission system planning assessments by
requiring the study of predefined contingencies that will ensure a level of
uniformity across planning regions.

TPL-008-1 Requirement R4 meets this directive by requiring each
responsible entity to develop and maintain System models within its
planning area consistent with that of the MOD-032 standard.
Specifically, Attachment 1 of MOD-032 requires information requested by
the Planning Coordinator or Transmission Planner necessary for modeling
purposes.

P 117: “[I]n addressing this directive, we expect NERC to determine
whether responsible entities will need to take additional steps to ensure
that the impacts of demand load response are accurately modeled in

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extreme weather studies, such as by analyzing demand load response as a
sensitivity, as is currently the case under Reliability Standard TPL-001-5.1.”
P124. “[W]e direct NERC to require the use of sensitivity cases to
demonstrate the impact of changes to the assumptions used in the
benchmark planning case. Sensitivity analyses help a transmission planner
to determine if the results of the base case are sensitive to changes in the
inputs. The use of sensitivity analyses is particularly necessary when
studying extreme heat and cold events because some of the assumptions
made when developing a base case may change if temperatures change –
for example, during extreme cold events, load may increase as
temperatures decrease, while a decrease in temperature may result in a
decrease in generation. We… direct NERC to define during the Reliability
Standard development process a baseline set of sensitivities for the new or
modified Reliability Standard. While we do not require the inclusion of any
specific sensitivity in this final rule, NERC should consider including
conditions that vary with temperature such as load, generation, and system
transfers.”
P125. “We…believe that responsible entities should be free to study
additional sensitivities relevant to their planning areas…cooperation will be
necessary between responsible entities conducting extreme heat and
extreme cold weather studies and other registered entities within their
extreme weather study footprints to ensure the selection of appropriate
sensitivities.”
P134. “[W]e directs NERC to require in the new or modified Reliability
Standard the use of planning methods that ensure adequate consideration
of the broad characteristics of extreme heat and cold weather conditions.
We further direct NERC to determine during the standard development
process whether probabilistic elements can be incorporated into the new

Consideration of Directives

This directive is addressed in proposed TPL-008-1 through Requirements R4
and R8. Per Requirement R4 Part 4.1, the responsible entity is obligated to
develop and maintain benchmark planning cases that include seasonal and
temperature dependent adjustments for Load, generation, Transmission,
and transfers to represent the System conditions of the selected
benchmark temperature events for one of the years in the Long-Term
Transmission Planning Horizon. Per Requirement R4 Part 4.2, the
responsible entity is obligated to develop and maintain sensitivity cases by
changing at least one of the following conditions in the benchmark
planning cases: generation, real and reactive forecasted Load, or transfers.
In addition, the responsible entities are required to coordinate among
adjacent impacted Planning Coordinators and Transmission Planners, and
other designated study entities, which an Interconnection. (Requirement
R3)

The Standard Drafting Team discussed probabilistic elements and
determined while probabilistic analysis would be a good step forward, it
would be better suited for the future as the methodology, process, and
tools mature.

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or modified Reliability Standard and implemented presently by responsible
entities. If NERC identifies probabilistic elements which responsible entities
can feasibly implement and that would improve upon existing planning
practices, we expect the inclusion of those methods in the proposed
Reliability Standard.”
P138. “[W]e direct NERC to identify during the standard development
process any probabilistic planning methods that would improve upon
existing planning practices, but that NERC deems infeasible to include in
the proposed Reliability Standard at this time. If any such methods are
identified, NERC shall describe in its petition for approval of the proposed
Reliability Standard the barriers preventing the implementation of those
probabilistic elements. We intend to use this information to determine
whether and what next steps may be warranted to facilitate the use of
probabilistic methods in transmission system planning practices.”
P152. “[W]e direct NERC to require in the new or modified Reliability
Standard the development of extreme weather corrective action plans for
specified instances when performance standards are not met. In addition,
as explained below, we direct NERC to develop certain processes to
facilitate interaction and coordination with applicable regulatory
authorities or governing bodies responsible for retail electric service as
appropriate in implementing a corrective action plan.”
P155: “[T]he Commission is not directing any specific result or content of
the corrective action plan.”
P157. “[W]e direct NERC to require in the new or modified Reliability
Standard the development of corrective action plans that include
mitigation for specified instances where performance requirements for
extreme heat and cold events are not met—i.e., when certain studies

Consideration of Directives

Probabilistic assessment of generation and transmission facilities for the
benchmark planning cases was discussed during the process of drafting the
TPL-008-1 standard. However, based on the actual extreme heat and
extreme cold events that have occurred, outages for generation and
transmission facilities were unique for each of these events. Thus, it was
challenging to draw correlation for the outages that occurred for different
extreme heat and cold events for different regions and different
timeframes. In addition, the data that were available from these events
were limited to perform an adequate probabilistic assessment. Due to
these reasons, the Standard Drafting Team has decided not to pursue any
probabilistic assessment for the current TPL-008-1 standard. This, however,
does not preclude future development of probabilistic assessment when
having additional data, as well as mature methodology, process and tools
that can provide meaningful probabilistic assessment for generation and
transmission outages under extreme temperature conditions.
The directive is addressed in the proposed TPL-008-1 Requirement R9.
When the benchmark planning case study results indicate the System is
unable to meet performance requirements for P0 and P1 Contingencies,
Corrective Action Plans must be developed. Additionally, in accordance
with Requirement R9.1, the responsible entities shall make their Corrective
Action Plan (CAP) available and solicit feedback from applicable regulatory
authorities or governing bodies responsible for retail electric service issues.

The directive is addressed in the proposed TPL-008-1 Requirement R9.
When the benchmark planning case study results indicate the system is
unable to meet performance requirements for P0 and P1 Contingencies,
Corrective Action Plans must be developed.

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conducted under the Standard show that an extreme heat or cold event
would result in cascading outages, uncontrolled separation, or instability.”
P158: “[W]e give NERC in this final rule the flexibility to specify the
circumstances that require the development of a corrective action plan.”
P165. “[w]e direct NERC to require in the new or modified Reliability
Standard that responsible entities share their corrective action plans with,
and solicit feedback from, applicable regulatory authorities or governing
bodies responsible for retail electric service issues.”
P167. “Further, because an important goal of transmission planning is to
avoid load shed, any responsible entity that includes non-consequential
load loss in its corrective action plan should also identify and share with
applicable regulatory authorities or governing bodies responsible for retail
electric service alternative corrective actions that would, if approved and
implemented, avoid the use of load shedding.”
P188. “[W]e direct NERC to submit a new or modified Reliability Standard
within 18 months of the date of publication of this final rule in the Federal
Register. Further, we direct NERC to propose an implementation timeline
for the new or modified Reliability Standard, with implementation
beginning no later than 12 months after the effective date of a Commission
order approving the proposed Reliability Standard.”

P193. “[W]e direct NERC to establish an implementation timeline for the
proposed Reliability Standard. In complying with this directive, NERC will
have discretion to develop a phased-in implementation timeline for the
different requirements of the proposed Reliability Standard (i.e.,

Consideration of Directives

The directive is addressed in the proposed TPL-008-1 Requirement R9.
Requirement R9.1 requires the responsible entities to make their CAP
available and solicit feedback from applicable regulatory authorities or
governing bodies responsible for retail electric service issues.
This directive is addressed in proposed TPL-008-1 Requirement R9.
As stipulated in Requirement R9.2, when Non-Consequential Load Loss is
utilized as an element of a CAP for the Table 1 P1 Contingency, the
responsible entity must document the alternative(s) considered, and notify
the applicable regulatory authorities or governing bodies responsible for
retail electric service issues.
The directive is addressed with the publication of TPL-008-1 and will be
filed with the regulatory government no later than December 23, 2024,
within 18 months of the date Order No. 896 was published in the Federal
Register.
The implementation plan addresses Requirement R1 becoming effective 12
months from the effective date of the Commission order approving the
TPL-008-1. In addition, phased-in approaches have been provided for other
Requirements needing additional time. See the TPL-008-1 Implementation
Plan.
The implementation plan addresses Requirement R1 becoming effective 12
months from the effective date of the Commission order approving the
TPL-008-1. In addition, phased-in approaches have been provided for other

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developing benchmark cases, conducting studies, developing corrective
action plans). However, this phased-in implementation must begin within
12 months of the effective date of a Commission order approving the
proposed Reliability Standard and must include a clear deadline for
implementation of all requirements.”

Consideration of Directives

Requirements needing additional time. See the TPL-008-1 Implementation
Plan.

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Limited Disclosure

DRAFT ERO Enterprise Process for TPL-008-1
Benchmark Weather Event Development and
Maintenance
Standards Development and Engineering Process Document
July 2024

Background

This Electric Reliability Organization (ERO) Enterprise Process for TPL-008-1 1 Benchmark Weather Event
Development and Maintenance addresses how ERO Enterprise staff will develop and maintain a library of
benchmark weather events (herein as the Weather Event Library) to be used by Planning Coordinators and
Transmission Planners for TPL-008-1 studies. Per Requirement R3 of TPL-008-1 and consistent with
directives outlined in FERC Order No. 896 2, Planning Coordinators and Transmission Planners will select and
use events from the Weather Event Library to develop their benchmark planning cases.

Purpose

The purpose of this process document is to formalize a repeatable approach to develop and maintain the
Weather Event Library. While both the TPL-008-1 study requirements and this process are in the initial
stages of development, it is essential that industry is informed of this process and how it will be designed
and implemented following the completion of NERC Project 2023-07. This process document outlines an
initial set of process objectives and approach but is not considered to be complete at this time. This
document will be revised as needed throughout the development of NERC Project 2023-07.

Document Maintenance

NERC will maintain this document to assure it is consistent with acceptable practices and publicly available.
This document will be reviewed as it is implemented. Updates will be made by NERC Standards
Development and Engineering, as needed, to reflect lessons learned as the process matures. Any
substantive changes to this process, supplemental/attached criteria, or other guidance to be used by NERC
in developing additional benchmark events, archiving/removing benchmark events, or other modifications
to the Weather Event Library, will be reviewed in consultation with NERC Legal, NERC Compliance
Assurance, Regional Entity staff, and FERC. Approved substantive revisions to this document will be detailed
in the Appendix, broadly communicated to industry, and included as part of informational filings to FERC.

1
2

Link pending final approval of TPL-008-1
FERC Docket No. RM22-10-000; Order No. 896; https://www.ferc.gov/media/e-1-rm22-10-000; June 15, 2023

RELIABILITY | RESILIENCE | SECURITY

Definitions

Refer to the NERC Glossary of Terms 3 for the below capitalized terms used in this process.
•

Affected Regional Entity (ARE)

•

Compliance Enforcement Authority (CEA)

•

Coordinated Oversight

•

Extreme Temperature Assessment (ETA)

•

Lead Regional Entity (LRE)

•

Multi-Region Registered Entity (MRRE)

Process Overview

The following is a five-year iterative process coinciding with Planning Coordinator and Transmission Planner
implementation of TPL-008-1. As TPL-008-1 and associated benchmark event(s) will be submitted to FERC
in December 2024, the first iteration of this process will cover five years (2025—2029).
•

•

•

•

3
4

December 2024


Weather Event Library developed and ready to go live for industry.



Benchmark Events, for the first five-years required per the TPL-008-1 Reliability Standard,
completed and uploaded to the Weather Event Library.

Year One (2025):


ERO to provide Weather Event Library training and how to request approval for entity-created
benchmark events.



ERO to engage with industry subject matter experts (SMEs), Planning Coordinators, research
labs, and trade organizations, and NERC technical committees on additional and updated criteria
for developing benchmark events.

Year Two (2026):


ERO to initiate review of benchmark event criteria, identify any changes needed, and
incorporate feedback from year one.



ERO to deliver a webinar on updated criteria for developing benchmark events.

Year Three (2027):


ERO to develop new benchmark events 4 based on updated criteria in year two.



ERO to update the Weather Event Library with updated benchmark events.



ERO to review any PC submitted benchmark events and determine approval.

NERC Glossary of Terms: Glossary_of_Terms.pdf (nerc.com)
Note: This is for the second iteration of benchmark events being developed.

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

2

o If approved, will be added to the Weather Event Library.
o If not approved, a response will be submitted to the entity explaining how the submittal did
not follow the process or sufficiently meet criteria as outlined in the process below.
•

Year Four (2028):


ERO to review any PC submitted benchmark events and determine approval.
o If approved, will be added to the Weather Event Library.
o If not approved, a response will be submitted to the entity.

•

Year Five (2029):


ERO to File informational filing with FERC.



ERO to conduct review of this process and make necessary revisions based on lessons-learned
and feedback (e.g., CMEP feedback loops, FERC, SMEs)



ERO to provide training on benchmark event process and changes to the Weather Event Library.

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

3

Year 1
Year 2
Year 3
Year4
Year 5

• Deliver Weather Event Library Training
• Develop training and guidance for planning case development

• Review and modify benchmark event criteria
• Informational session on updated criteria

• Update library with new/removed benchmark events
• (optional) Planning Coordinator due date to submit benchmark events based
on different criteria for ERO approval

• Informational filing to FERC for any change to criteria and modifications to
Weather Events Library

• Review process and revise based on lessons learned and other feedback loops
• Update Weather Event Library training

Criteria in Attachment B

Criteria for benchmark events to be drafted.

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

4

Submittal Process for Entity-Created Benchmark Events

Step 1 – Registered Entity Subm ittal
If a Planning Coordinator or group of Planning Coordinators determine that a benchmark event, other than
one provided in the Weather Event Library, would be a more accurate representation of extreme hot or
extreme cold events, then the entity will contact the ERO to submit the necessary information.

The entity shall submit the data requested in Attachment A: Benchmark Event Entity Submittal Form to a
secure site that will be established by the ERO. The ERO will acknowledge receipt of the submission in
writing within 15 days and review that all information requested in the Entity Submittal Template is
provided in the entity’s submittal. If the submittal is incomplete, the ERO will inform the entity to resubmit,
and the process will restart. The ERO will notify NERC Compliance Assurance when acknowledging receipt
of the submission.
The entity submitting the request may withdraw the request any time prior to the ERO communicating the
final determination.
Step 2 – ER O Enterprise R eview
NERC will form an ERO Enterprise Review Panel (review panel) comprised of not less than four (4) total
individuals from the applicable Regional Entity(s) and NERC. The review panel will perform a review of the
submitted information and develop a preliminary determination of whether the submitted information is
complete and that the usage of different, or differently applied, criteria does not conflict with the technical
rationale provided. This review panel will complete the review within 90 days of its acknowledgement of
the receipt of submission. During its review, the review panel may work through the ERO to request
additional information from the entity submitting the request.

If the review panel determines it will be unable to complete its review within the established timeframe,
the review panel, based on consultation with the managers of NERC Compliance Assurance and NERC Power
System Analysis, will establish a revised timeline for completing its review. The revised timeline for review
and determination will be provided to the entity by the ERO.
Step 3 – ER O Determ ination
The review panel will present to the NERC Vice President of Engineering and Standards for approval of the
preliminary determination as the ERO determination. The review panel will communicate the ERO
determination and rationale to NERC Compliance Assurance and the applicable Regional Entities.

The ERO will then communicate the ERO determination in writing to the PC(s) along with the rationale for
the determination within 30 days of NERC’s Vice President Engineering and Standards receiving the review
panel’s preliminary determination.

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

5

Step 1. (15-day process)
Entity submit Attachment A: Benchmark Event
Entity Submittal Form To ERO via secure site.
ERO has 15 days to acknowledge receipt of
submission .
Entity may withdraw request at anytime prior to
ERO communicating final determination.

Step 2. (90-day process)
ERO review panel will perform a review of the
submitted information and develop a preliminary
determination of whether the submitted information
is complete and that the usage of different, or
differently applied, criteria does not conflict with the
technical rationale provided

Step 3. (30-day process)
review panel will present to the NERC Vice President
of Engineering and Standards for approval of the
preliminary determination as the ERO determination.
communicate the ERO determination in writing to
the entity along with the rationale for the
determination.

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

6

Limited Disclosure

Attachment A: Benchmark Event Entity
Submittal Form

Per the process above, a registered Planning Coordinator, or group of Planning Coordinators, seeking to
include additional extreme temperature weather events to the NERC Weather Event Library must
provide the following information to NERC. Answers to questions should be narratives with summarized
technical rationales that are supported through documentation. Submittal of this form does not
guarantee approval of the weather event(s) to the Weather Event Library. Per the process above, NERC
will review the submittal form and provide a response either approving the event(s), rejecting the
event(s), or requesting additional information to be provided.

Entity Information
Entity name(s):
NCR#:
Primary entity contact name and
information:
Request submittal date:
Other Planning Coordinators impacted by
the proposed extreme temperature
weather event(s)

Benchmark Event Information
Development Criteria:
1. What criteria was applied
2. What was different than posted
NERC criteria, if any.
3. Technically substantive
rationale/study for why the
event(s) are more appropriate

RELIABILITY | RESILIENCE | SECURITY

Coordination


If this event is submitted on behalf
of more than one PC, please
provide details on the coordination
conducted. Otherwise, respond
“N/A”.

Additional information an entity wishes to
provide regarding benchmark event being
submitted.

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

8

Attachment B: Criteria used to develop the
benchmark events
Criteria

Criteria for benchmark events to be drafted.

TPL-008-1 ERO Enterprise Benchmark Weather Event Development and Maintenance
Process Document Version History
Version
1

Date
TBD

Owner
Standards Staff

Change tracking
Initial Version

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

9

Extreme Heat and Cold Weather Benchmark Events Example
July 2024

Introduction

This extreme heat and cold weather benchmark events document provides industry with information regarding the project scope, high level
criteria, and visual maps used to develop benchmark events. Historical meteorological data over the past 43 years (1980-2022) has been
provided for the examples listed below.
Additional work is needed to develop planning cases from weather event data. NERC is only providing the weather event data within the ERO
library and will continue to work with industry to develop guidance and promote training to developing planning cases.
This example is providing industry for awareness during the Standard Development process. Information herein is accurate to the date of this
posting. Additional events will be developed to complete the initial Weather Event Library.

Project Scoping

The below table shows what is included and not included for the first iteration of the benchmark events.
Scope of Weather Events
Temporal Coverage
Geographic Coverage
Data Consistency and Synchronization
Future Projections

Included for First Iteration
Extreme heat and cold temperature data
Long historical record of weather data.
Data for the entire continent, specifically the
U.S. and Canada
Correlated, consistent, and timesynchronized data.
Historical weather data

Not Included for First Iteration
Other weather events (renewable lulls, hydro
droughts, wildfires, hurricanes, etc.)
Only a few years of recent observations.
Unique datasets for specific zones.
Stitched-together datasets comprising
different events and/or datasets.
Climate projections of future weather

Screening for Extreme Heat and Extreme Cold Events

RELIABILITY | RESILIENCE | SECURITY

M ulti-day W eather Events
Calculated three-day rolling average temperatures for both extreme heat and extreme cold to identify multi-day periods of extreme heat/cold.
W ide-area Assessm ent
• Aggregated U.S. and Canada into 11 zones and evaluated average temperatures across wide-areas rather than smaller planning coordinators
• Evaluated the top 40 extreme heat and cold three-day periods for each zone and prioritized events that occurred across multiple zones during
the same event
• Ensured each zone had at least its top two worst events covered

Wide-area Boundaries

Adapted from the NERC Assessment Areas 1

1

•

SERC: combined NERC Assessment areas of SERC-East, SERC-Central, and SERC-Southeast into a single zone based on climate similarities.

•

Florida has significantly different weather patterns, which warrant separate treatment.

•

WECC-NW, WECC-SW, SERC, and SERC-FP were aggregated

NERC Assessment Areas.png (1590×661)

Extreme Heat and Cold Weather Benchmark Events Example

2

Extreme Cold Events
Rank of events by average three-day average min temperature, 1980-2022

Extreme Heat and Cold Weather Benchmark Events Example

3

Extreme Heat Events
Rank of events by average three-day average min temperature, 1980-2022

Extreme Heat and Cold Weather Benchmark Events Example

4

Winter Storm Elliott Examples

Winter storm Elliott provides entities with an extreme event example showing hour by hour data. This will allow entities the ability to locate
when their zone was most vulnerable and to gather data needed when building out its benchmark planning cases. The following figures
represent various instances of winter storm Elliott’s temperature.

Extreme Heat and Cold Weather Benchmark Events Example

5

Extreme Heat and Cold Weather Benchmark Events Example

6

Extreme Heat and Cold Weather Benchmark Events Example

7

Public

Standards Announcement

Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather
Formal Comment Period Open through August 22, 2024
Now Available

A 38-day formal comment period for draft two of TPL-008-1 – Transmission System Planning
Performance Requirements for Extreme Temperature Events is open through 8 p.m. Eastern,
Thursday, August 22, 2024.
The standard drafting team’s considerations of the responses received from the previous comment
period are reflected in this draft of the standard.
Reminder Regarding Corporate RBB Memberships

Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more than
the one permitted representative in a particular Segment must withdraw the duplicate membership(s)
prior to joining new ballot pools or voting on anything as part of an existing ballot pool. Contact
[email protected] to assist with the removal of any duplicate registrations.
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. An unofficial Word
version of the comment form is posted on the project page.
•

Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.

•

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

Additional ballots for the standard and implementation plan, as well as a non-binding poll of the
associated Violation Risk Factors and Violation Severity Levels will be conducted August 13-22, 2024.
For information on the Standards Development Process, refer to the Standard Processes Manual.

RELIABILITY | RESILIENCE | SECURITY

Public

For more information or assistance, contact Senior Standards Developer, Jordan Mallory (via email) or at
404-479-7358. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists"
from the "Service" drop-down menu and specify “Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather observer list” in the Description Box.

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 2023-07 Transmission Planning Performance Requirements for Extreme Weather | July 16, 2024

2

Comment Report
Project Name:

2023-07 Transmission Planning Performance Requirements for Extreme Weather | Draft 2

Comment Period Start Date:

7/16/2024

Comment Period End Date:

8/22/2024

Associated Ballots:

2023-07 Transmission Planning Performance Requirements for Extreme Weather Implementation Plan AB 2 OT
2023-07 Transmission Planning Performance Requirements for Extreme Weather TPL-008-1 AB 2 ST

There were 74 sets of responses, including comments from approximately 191 different people from approximately 118 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. The drafting team (DT) updated the Requirements in chronological order. Do you agree with the proposed TPL-008-1 Reliability Standard
Requirement layout? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural justification.
2. The DT updated Requirements R1 – R2 based on comments received. Do you agree with the updated proposed TPL-008-1 Reliability
Standard Requirements R1-R2? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural
justification.
3. The DT updated Requirements R3 – R5 based on comments received. Do you agree with the updated proposed TPL-008-1 Reliability
Standard Requirements R3-R5? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural
justification.
4. The DT updated Requirements R6 – R8 based on comments received. Do you agree with the updated proposed TPL-008-1 Reliability
Standard Requirements R6-R8? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural
justification.
5. The DT updated Requirement R9 based on comments received. Do you agree with the updated proposed TPL-008-1 Reliability Standard
Requirement R9? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural justification.
6. The DT updated Requirement R10 based on comments received. Do you agree with the updated proposed TPL-008-1 Reliability Standard
Requirement R10? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural justification.
7. The DT split out Table 1 into parts for better readability. Do you agree with the updated layout of Table 1? If you do not agree, please
provide your recommendation and technical justification.
8. The DT believes proposed modifications in TPL-008-1 provide entities with flexibility to meet the reliability objectives in a cost-effective
manner. Do you agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost-effective approaches,
please provide your recommendation and, if appropriate, technical or procedural justification.
9. Provide any additional comments for the standard drafting team to consider, including the provided technical rationale document, if
desired.

Organization
Name
MRO

Name

Anna
Martinson

Segment(s)

1,2,3,4,5,6

Region

MRO

Group Name

MRO Group

Group Member
Name
Shonda McCain

Group
Member
Organization

Group
Member
Segment(s)

Omaha Public 1,3,5,6
Power District
(OPPD)

Group Member
Region
MRO

Michael Brytowski Great River
Energy

1,3,5,6

MRO

Jamison Cawley

Nebraska
Public Power
District

1,3,5

MRO

Jay Sethi

Manitoba
Hydro (MH)

1,3,5,6

MRO

Husam Al-Hadidi Manitoba
1,3,5,6
Hydro
(System
Preformance)

MRO

Kimberly Bentley Western Area 1,6
Power
Adminstration

MRO

Jaimin Patal

Saskatchewan 1
Power
Coporation
(SPC)

MRO

George Brown

Pattern
Operators LP

5

MRO

Larry Heckert

Alliant Energy 4
(ALTE)

MRO

Terry Harbour

MidAmerican
Energy
Company
(MEC)

1,3

MRO

Dane Rogers

Oklahoma
Gas and
Electric
(OG&E)

1,3,5,6

MRO

Seth Shoemaker Muscatine
Power &
Water

1,3,5,6

MRO

Michael Ayotte

ITC Holdings

1

MRO

Andrew Coffelt

Board of
1,3,5,6
Public UtilitiesKansas (BPU)

MRO

Peter Brown

Invenergy

MRO

5,6

Dominion Dominion
Resources,
Inc.

Midcontinent
ISO, Inc.

Barbara
Marion

Bobbi Welch

5

2

Dominion

Angela Wheat

Southwestern 1
Power
Administration

MRO

Bobbi Welch

Midcontinent
ISO, Inc.

2

MRO

Joshua Phillips

Southwest
Power Pool

2

MRO

Patrick Tuttle

Oklahoma
Municipal
Power
Authority

4,5

MRO

Victoria Crider

Dominion

3

NA - Not
Applicable

Barbara Marion

Dominion

5

NA - Not
Applicable

Sean Bodkin

Dominion

6

NA - Not
Applicable

Steven Belle

Dominion

1

NA - Not
Applicable

CAISO

2

WECC

Electric
Reliability
Council of
Texas, Inc.

2

Texas RE

IESO

2

NPCC

ISO-NE

2

NPCC

MISO

2

RF

Gregory Campoli New York
Independent
System
Operator

2

NPCC

Charles Yeung

SPP

2

MRO

Elizabeth Davis

PJM

2

RF

NA - Not
Applicable

WECC

NA - Not
Applicable

WECC

Christopher Lamb CHPD

NA - Not
Applicable

WECC

Laryn Brinkman

CHPD

NA - Not
Applicable

WECC

Zach Zornes

CHPD

NA - Not
Applicable

WECC

MRO,RF,SERC ISO/RTO
Ali Miremadi
Council
Kennedy Meier
Standards
Review
Committee
(SRC) Project
2023-07 TPL- Helen Lainis
008-1 Draft #2
Keith Jonassen
Bobbi Welch

Western
Power Pool

Chelsea
Loomis

NA - Not
Applicable

WECC

WPP
Guiha Wang
BC Hydro
Consortium of
Engineers
Berhanu Tesema BPA

Santee
Cooper

Public Utility
District No. 1
of Chelan
County

FirstEnergy FirstEnergy
Corporation

Chris Wagner

1

Joyce Gundry 3

Mark Garza

4

Santee
Cooper

CHPD

FE Voter

Stephen
Longmuir

IPCO

NA - Not
Applicable

WECC

Jessica
Boatwright

NWMT

NA - Not
Applicable

WECC

Daniel Baye

PAC

NA - Not
Applicable

WECC

Rachit Aurora

PSE

NA - Not
Applicable

WECC

Nima Miri

SCL

NA - Not
Applicable

WECC

Rob Jones

SCL

NA - Not
Applicable

WECC

Ken Che

SNPD

NA - Not
Applicable

WECC

Tuan Dang

SNPD

NA - Not
Applicable

WECC

Ben Hutchins

WPP

NA - Not
Applicable

WECC

Rene' Free

Santee
Cooper

1,3,5,6

SERC

Christie Pope

Santee
Cooper

1,3,5,6

SERC

Rebecca Zahler

Public Utility
District No. 1
of Chelan
County

5

WECC

Joyce Gundry

Public Utility
District No. 1
of Chelan
County

3

WECC

Diane Landry

Public Utility
District No. 1
of Chelan
County

1

WECC

Robert Witham

Public Utility
District No. 1
of Chelan
County

6

WECC

Julie Severino

FirstEnergy FirstEnergy
Corporation

1

RF

Aaron
Ghodooshim

FirstEnergy FirstEnergy
Corporation

3

RF

Southern
Pamela Hunter 1,3,5,6
Company Southern
Company
Services, Inc.

Black Hills
Corporation

Northeast
Power
Coordinating
Council

SERC

Rachel Schuldt 6

Ruida Shu

1,2,3,4,5,6,7,8,9,10 NPCC

Southern
Company

Robert Loy

FirstEnergy FirstEnergy
Solutions

5

RF

Mark Garza

FirstEnergyFirstEnergy

1,3,4,5,6

RF

Stacey Sheehan

FirstEnergy FirstEnergy
Corporation

6

RF

Matt Carden

Southern
1
Company Southern
Company
Services, Inc.

SERC

Joel Dembowski

Southern
Company Alabama
Power
Company

3

SERC

Ron Carlsen

Southern
Company Southern
Company
Generation

6

SERC

Leslie Burke

Southern
Company Southern
Company
Generation

5

SERC

Black Hills
Corporation

1

WECC

Black Hills
Corporation

3

WECC

Rachel Schuldt

Black Hills
Corporation

6

WECC

Carly Miller

Black Hills
Corporation

5

WECC

Sheila Suurmeier Black Hills
Corporation

5

WECC

Gerry Dunbar

Northeast
Power
Coordinating
Council

10

NPCC

Deidre Altobell

Con Edison

1

NPCC

Michele Tondalo

United
Illuminating
Co.

1

NPCC

Black Hills
Micah Runner
Corporation All Segments Josh Combs

NPCC RSC

Stephanie UllahMazzuca

Orange and
Rockland

1

NPCC

Michael Ridolfino Central
1
Hudson Gas &
Electric Corp.

NPCC

Randy Buswell

Vermont
1
Electric Power
Company

NPCC

James Grant

NYISO

2

NPCC

Dermot Smyth

Con Ed 1
Consolidated
Edison Co. of
New York

NPCC

David Burke

Orange and
Rockland

3

NPCC

Peter Yost

Con Ed 3
Consolidated
Edison Co. of
New York

NPCC

Salvatore
Spagnolo

New York
Power
Authority

1

NPCC

Sean Bodkin

Dominion Dominion
Resources,
Inc.

6

NPCC

David Kwan

Ontario Power 4
Generation

NPCC

Silvia Mitchell

NextEra
1
Energy Florida Power
and Light Co.

NPCC

Sean Cavote

PSEG

4

NPCC

Jason Chandler

Con Edison

5

NPCC

Tracy MacNicoll

Utility Services 5

NPCC

Shivaz Chopra

New York
Power
Authority

6

NPCC

Vijay Puran

New York
6
State
Department of
Public Service

NPCC

David Kiguel

Independent

7

NPCC

Joel Charlebois

AESI

7

NPCC

Dominion Dominion
Resources,
Inc.

Shannon
Mickens

Sean Bodkin

Shannon
Mickens

6

Dominion

MRO,SPP
RE,WECC

SPP RTO

Joshua London

Eversource
Energy

1

NPCC

Jeffrey Streifling

NB Power
Corporation

1,4,10

NPCC

Joel Charlebois

AESI

7

NPCC

John Hastings

National Grid

1

NPCC

Erin Wilson

NB Power

1

NPCC

James Grant

NYISO

2

NPCC

Michael
Couchesne

ISO-NE

2

NPCC

Kurtis Chong

IESO

2

NPCC

Michele Pagano

Con Edison

4

NPCC

Bendong Sun

Bruce Power

4

NPCC

Carvers Powers

Utility Services 5

NPCC

Wes Yeomans

NYSRC

7

NPCC

Chantal Mazza

Hydro Quebec 1

NPCC

Nicolas Turcotte

Hydro Quebec 2

NPCC

Victoria Crider

Dominion
Energy

3

NA - Not
Applicable

Sean Bodkin

Dominion
Energy

6

NA - Not
Applicable

Steven Belle

Dominion
Energy

1

NA - Not
Applicable

Barbara Marion

Dominion
Energy

5

NA - Not
Applicable

Shannon Mickens Southwest
Power Pool
Inc.

2

MRO

Mia Wilson

Southwest
Power Pool
Inc.

2

MRO

Eddie Watson

Southwest
Power Pool
Inc.

2

MRO

Erin Cullum

Southwest
Power Pool
Inc.

2

MRO

Jonathan Hayes

Southwest
Power Pool
Inc.

2

MRO

Western
Electricity
Coordinating
Council

Steven
Rueckert

Tim Kelley

Tim Kelley

10

WECC

WECC

SMUD and
BANC

Jeff McDiarmid

Southwest
Power Pool
Inc.

2

MRO

Scott Jordan

Southwest
Power Pool
Inc

2

MRO

Lottie Jones

Southwest
Power Pool
Inc.

2

MRO

Sherri Maxey

Southwest
Power Pool
Inc.

2

MRO

Josh Phillips

Southwest
Power Pool
Inc.

2

MRO

Steve Rueckert

WECC

10

WECC

Curtis Crews

WECC

10

WECC

Nicole Looney

Sacramento
Municipal
Utility District

3

WECC

Charles Norton

Sacramento
Municipal
Utility District

6

WECC

Wei Shao

Sacramento
Municipal
Utility District

1

WECC

Foung Mua

Sacramento
Municipal
Utility District

4

WECC

Nicole Goi

Sacramento
Municipal
Utility District

5

WECC

Kevin Smith

Balancing
Authority of
Northern
California

1

WECC

1. The drafting team (DT) updated the Requirements in chronological order. Do you agree with the proposed TPL-008-1 Reliability Standard
Requirement layout? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural justification.
Long Island Power Authority

Answer

Yes

Document Name

(if an attachment is provided by submitter)

Comment
Submitter’s comments
Likes

0

# of other submitters who agree with these comments

Dislikes

0

# of other submitters who disagree with these comments

Response
(Drafting team’s response to submitter’s comments)
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

No

Document Name
Comment
The MRO NERC Standards Review Forum (NSRF) recommends the following changes to the order of the requirements:
· R8 should be moved up. The standard needing to be met once every five years should be right up front.
· R2 and R4 need to be together as they describe the cases. They should also clearly denote both power flow and dynamics benchmark and sensitivity
cases need to be constructed.
Please see the process flow proposed in Attachment A to these comments which illustrates a logical flow.
Likes

1

Dislikes

Scott Brame, N/A, Brame Scott
0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Document Name
Comment

No

Evergy supports and incorporates by reference the comments of the Midwest Reliability Organization's NERC Standards Review Forum (MRO NSRF)
on question 1
Likes

0

Dislikes

0

Response
Amy Wilke - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
ATC supports the MRO NSRF comments.
Likes

0

Dislikes

0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

No

Document Name
Comment
Tri-State supports the comments submitted by the MRO NSRF.
Likes

0

Dislikes

0

Response
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer
Document Name
Comment

No

It’s unclear to SPP how the “chronological order” helps the success of the proposed standard to move forward. Industry has identified too many
unresolved issues with the proposed requirements to make any type of determination. For example, the drafting team has not provided any resolution or
vision on how the industry will use the NERC (ERO) approved library since it has not been created at this time.
Moreover, the drafting team has not provided any tangible solutions/details in reference to joint coordination with neighboring entities as well as
appropriate data collection via MOD-032 to build quality models to conduct this assessment and produce quality results.
SPP recommends that the drafting team provides clarity/tangible solutions via technical documentation to help industry get a better understanding on
NERC’s expectations for this standard.
Likes

0

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0

Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
The chronological order is immaterial at this time. The issues outlined in the subsequent comments need to be addressed before the chronological
order of requirements can be determined.
Likes

0

Dislikes

0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy Houston Electric, LLC (CEHE) disagrees with the proposed standard overall and definition of an “Extreme Temperature
Assessment”. Clarification on what “extreme heat” and “extreme cold temperature” and details on the meaning of benchmark events are needed.
CEHE has identified a few issues related to the Electric Reliability Organization (ERO) library. First, there is little information on the overall reliability
benefit of the standard and details of exactly what the library will contain, how it will get populated, or which forms of data will be kept. Second, there is
no requirement that authorizes the upkeep and ongoing maintenance of said library. Third, using one extreme heat benchmark, and one extreme cold
benchmark, as approved by the ERO, ignores local extreme temperature events, and may exclude entities who may experience micro weather
events. Extreme Temperature Assessments should include regional and significant local events. It is not clear who in the ERO approves and maintains
a library of benchmarked events, or how this process is done for transparency. It is difficult to support or agree with the proposed language if the ERO
has not made the library available and defined “Extreme Temperature Assessment” criteria or defined benchmark event criteria. CEHE would like

clarification on the benchmark events, and further clarification on criteria to determine this responsibility. CEHE believes the PC should assume the
responsibility to provide these system wide studies, since TPs already provide BPS data to the PC. The approved library of benchmark events is
currently not available to Transmission Planners (TPs), therefore, CEHE cannot support any of the proposed requirements as written.
Likes

0

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0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
None.
Likes

0

Dislikes

0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
Comment
FirstEnergy has no concerns with the order of the requirements.

Likes

0

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0

Response
Daniel Gacek - Exelon - 1
Answer
Document Name
Comment

Yes

Exelon agrees with the proposed TPL-008-1 Reliability Standard Requirement layout.
Likes

0

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0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
Likes

0

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0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

Yes

Document Name
Comment
Black Hills Corporation has no concerns with the updated chronological order of the requirements.
Likes

0

Dislikes

0

Response
Richard Vendetti - NextEra Energy - 5
Answer

Yes

Document Name
Comment
NextEra is not concerned with the order of the requirements.

Likes

0

Dislikes

0

Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI is not concerned with the order of the requirements.
Likes

0

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0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

Yes

Document Name
Comment
Please see comments from EEI
Likes

0

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0

Response
Greg Sorenson - Greg Sorenson On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Greg Sorenson
Answer

Yes

Document Name
Comment
Our comments still haven’t been addressed. “Extreme heat and extreme cold temperatures hasn’t been defined.” We would prefer to see some
percentile-based definition or other quantifiable requirement.
Likes
Dislikes

0
0

Response
Kinte Whitehead - Exelon - 3
Answer

Yes

Document Name
Comment
Exelon agrees with the proposed TPL-008-1 Reliability Standard Requirement layout.
Likes

0

Dislikes

0

Response
Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer

Yes

Document Name
Comment
While ISO-NE believes that the Standard as written includes the requirements needed, there are areas in which the Standard Requirements could be
combined or moved around, such as moving R8 earlier as a requirement describing how often a process should be completed is typically included as
early as possible within the Standard.
Recommendation: Make R8, R2, and adjusting the rest accordingly.
ISO-NE recommends that the SDT review areas where Requirements could be combined to simplify or clarify the flow of requirements. TPL-007 is an
example of how out of order requirements can confuse the industry, which required a flowchart in the technical rationale to illustrate the order in which
requirements are performed.
Likes

0

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0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer
Document Name
Comment

Yes

ITC does not have any concerns with the order of the requirements.
Likes

0

Dislikes

0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

Yes

Document Name
Comment
PGAE agrees with the chronological order of the proposed TPL-008-1.
Likes

0

Dislikes

0

Response
Robert Blackney - Edison International - Southern California Edison Company - 1
Answer

Yes

Document Name
Comment
See comments submitted by Edison Electric Institute
Likes

0

Dislikes

0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

Yes

Document Name
Comment
Likes

1

Dislikes

Snohomish County PUD No. 1, 3, Chaney Holly
0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Chelsea Loomis - Western Power Pool - NA - Not Applicable - WECC, Group Name WPP Consortium of Engineers
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Document Name

Yes

Comment
Likes

0

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0

Response
Ronald Hoover - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Fon Hiew - NB Power Corporation - New Brunswick Power Transmission Corporation - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Zahid Qayyum - New York Power Authority - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
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 NPCC RSC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Robert Jones - Seattle City Light - 1,3,4,5,6
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Donald Lock - Talen Generation, LLC - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Barbara Marion - Dominion - Dominion Resources, Inc. - 5, Group Name Dominion
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

Response
Robert Follini - Avista - Avista Corporation - 3
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Kevin Conway - Western Power Pool - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Junji Yamaguchi - Hydro-Quebec (HQ) - 5
Answer
Document Name

Yes

Comment
Likes

0

Dislikes

0

Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

Yes

Document Name
Comment
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0

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0

Response
Helen Lainis - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Michele Tondalo - United Illuminating Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Israel Perez - Israel Perez On Behalf of: Laura Somak, Salt River Project, 3, 6, 5, 1; Mathew Weber, Salt River Project, 3, 6, 5, 1; Thomas
Johnson, Salt River Project, 3, 6, 5, 1; Timothy Singh, Salt River Project, 3, 6, 5, 1; - Israel Perez
Answer
Document Name

Yes

Comment
Likes

0

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0

Response
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Teresa Krabe - Lower Colorado River Authority - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Matt Lewis - Lower Colorado River Authority - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Ben Hammer - Western Area Power Administration - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Bobbi Welch - Midcontinent ISO, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee (SRC) Project 2023-07 TPL-008-1 Draft #2
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Apollonia Gonzales - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
John Brewer - National Energy Technology Laboratory - 9 - NA - Not Applicable
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Usama Tahir - Seminole Electric Cooperative, Inc. - 3
Answer
Document Name
Comment
No comment
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0

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0

Response
Elizabeth Davis - Elizabeth Davis On Behalf of: Thomas Foster, PJM Interconnection, L.L.C., 2; - Elizabeth Davis
Answer
Document Name
Comment
PJM recommends the following changes to the order of the requirements:
R8 should be moved up. The standard needing to be met once every five years should be right up front.
R2 and R4 need to be together as they describe the cases. They should also clearly denote that both power flow and dynamics benchmark and
sensitivity cases need to be constructed.

Likes

0

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Response

0

2. The DT updated Requirements R1 – R2 based on comments received. Do you agree with the updated proposed TPL-008-1 Reliability
Standard Requirements R1-R2? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural
justification.
Long Island Power Authority

Answer

No

Document Name

(if an attachment is provided by submitter)

Comment
The text of Requirement #2 mentions “benchmark library, approved and maintained by the Electric Reliability Organization
(ERO)”.
Similar to Attachment 1 of TPL-007-4, we recommend that the final version of the standard include an attachment that contains
details of the extreme heat and extreme cold benchmark events, or at least some mention of the public facing library (site) to be
created by Q4 2024 (as mentioned in the TPL-008 webinar in July 2024) and maintained by NERC. Ideally, stakeholders should
have the opportunity to review the list of events and understand how they apply to their region, and what assessments they would
need to conduct ahead of being asked to approve this standard.
Likes

0

Dislikes

# of other submitters who agree with these comments
0

# of other submitters who disagree with these comments

Response
(Drafting team’s response to submitter’s comments)
John Brewer - National Energy Technology Laboratory - 9 - NA - Not Applicable
Answer

No

Document Name
Comment
(R1) No issue.

(R2) R2 requirements refer to the benchmark library, approved and maintained by the ERO. However, Draft of ERO Enterprise Process for TPL-008-1 Benchmark
Weather Event Development and Maintenance (July 2004) states “ERO Enterprise staff will develop and maintain a library of benchmark weather events (herein as
the Weather Event Library) to be used by Planning Coordinators and Transmission Planners for TPL-008-1 studies.” Consider aligning nomenclature “benchmark
library” and “Weather Event Library” in these two documents so there is no confusion as documents advance.

(R2) R2 states that each responsible entity shell select extreme events from the library; however, it does not specify should they choose from the benchmark
events(s) that NERC will submit to FERC in December 2024 (and every five years after that, e.g., 2029, 2034), or any event from the NERC’s “live” Weather Event

Library that will go through updated from 2025 – 2029 as described in the Draft ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and
Maintenance.

(R2) R2 states that selection should be from “the benchmark library, approved and maintained by the ERO.” NERC should be more specific about who will approve
the library in the ERO. Draft ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance states that “NERC will form an ERO
Enterprise Review Panel (review panel) comprised of not less than four (4) total individuals from the applicable Regional Entities and NERC” to review entity-created
benchmark events. Should the same review panel review all benchmark temperature event(s) from the library, including those developed by ERO? We suggest to
replacing the text “approved and maintained by the Electric Reliability Organization (ERO)” with “approved and maintained by the Electric Reliability Organization
(ERO) Enterprise Review Panel”.
Likes

0

Dislikes

0

Response
Robert Blackney - Edison International - Southern California Edison Company - 1
Answer

No

Document Name
Comment
See comments submitted by Edison Electric Institute
Likes

0

Dislikes

0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

No

Document Name
Comment
NERC entities operate transmission and generation assets across an enormous service territory and a variety of weather conditions. Every entity has
its own unique “extreme weather condition(s)” to manage. PGAE would like to better understand the benefits of using a centralized benchmark library
(still under development) over localized weather condition assessments.
Likes

0

Dislikes
Response

0

Usama Tahir - Seminole Electric Cooperative, Inc. - 3
Answer

No

Document Name
Comment
The SDT should choose either the PC or TP to be responsible for R1. By allowing the responsible party to be either the TP or PC, the two parties may
not agree on all terms or there may result a reliability gap. Seminole would like clarification on which responsibilities will belong to the Planning
Coordinator and Transmission Planner. Seminole would like a longer implementation timeline of R2,R3,R4,R5,R6, R7, R8, R9, R10, R11
Likes

0

Dislikes

0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CEHE agrees with EEI comments, we continue to have concerns with Requirement R2 because this requirement relies on an ERO developed
benchmark library that is being developed without industry review and approval, and as of this draft we continue to only have only superficial insights
into this library. Moreover, the ERO was directed to set a framework with this Reliability Standard that included specific bounds by which the industry
could conduct their extreme weather assessments. Yet, TPL-008-1 still does not contain any specific boundary limits that could guide responsible
entities in their Extreme Weather Assessments or otherwise limit what might be contained or added to the Extreme Weather Event Library, now or in the
future. For these reasons we ask that the DT set clear bounds that guide these Extreme Weather Assessments and set boundaries for any future
changes to the Extreme Weather Event Library.
Likes

0

Dislikes

0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

No

Document Name
Comment
•

ITC believes R2 should be assigned to the Planning Coordinator within the standard. To ITC the assignment of R2 to the Planning Coordinator
would seem to make the work of the standard flow in a more cohesive manner. To ITC the events should be chosen by the PC and such that
they fit within the process being developed by the PC in R3.

•

The standard has the ERO identifying the weather events in the benchmark library. Is the ERO the correct entity to perform this work?
o The ERO is not an entity that is auditable. What happens if their work product is completed late? Also, will the entity identified to
develop the benchmark weather events provide entities the opportunity to comment on the identified events?

Likes

0

Dislikes

0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

No

Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments:
Like Attachment 1 of TPL-007-4, we suggest that the standard includes an attachment that contains the extreme heat and extreme cold benchmark
events. This is needed because stakeholders should have the opportunity to review the list of events and understand how they apply to their region,
and what assessments they would need to conduct ahead of being asked to approve this standard.
Are the benchmark events considering regional-specific extremes? We are interested in seeing how Canadian, provincial attributes are considered
within the ERO benchmark library. It is extremely important that Canadian benchmarks are adequately reflected and/or provide flexibility for Canadian
entities to make appropriate changes to the ERO benchmark library.
Likes

0

Dislikes

0

Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
Comments provided to the previous draft suggested adding the “maintaining models” to the wording for R1 as that is an important joint responsibility for
the PC and TP to do in support of the assessment. The modifications in draft 2 do not address this concern.
The modifications to R2 in this draft did not improve the overall requirement from draft 1. It is understood the ERO is tasked with developing and
maintaining a benchmark events library for use by the responsible entity in the required assessment. It is not clear what the events will ultimately be
and how the benchmark events library is to be maintained and updated. The SDT should define and clarify the process for maintaining the benchmark
library. GTC also recommends that the PC & TP be involved in the development and/or approval of the benchmark events.

Likes

0

Dislikes

0

Response
Kinte Whitehead - Exelon - 3
Answer

No

Document Name
Comment
R1 – Exelon does not have any objections to the proposed language for Requirement R1.
R2 – Exelon believes it is not appropriate to assign the Electric Reliability Organization (ERO) responsibility within the standard requirement that directly
impacts the compliance to the standard requirement. There is a compliance risk to the directly assigned entity if the ERO fails to uphold its responsibility
to maintain the database. We suggest coordinating this the way MMWG is coordinated through ERAG in the Eastern Interconnection.
Additionally, Exelon supports the comments submitted by the EEI for this question.
Likes

0

Dislikes

0

Response
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer

No

Document Name
Comment
SPP has several concerns in reference to Requirement R2. The first concern focuses on the timing horizon of the study. As we reviewed draft 2, it was
unclear if the assessment was intended for a near-term or long-term (six to ten year) horizon. In our review of TPL-001-5, Requirement R2 addresses
both near and long-term assessments. Can we make the same assumption for TPL-008?
We recommend that the drafting team provide some clarity on the time horizon of the study for TPL-008. In the case the drafting team has the same
intention for this standard as that of TPL-001-5, we recommend that they structure language like TPL-001-5 (i.e. 2.1, and 2.5).
As for the second concern, it is unclear in TPL-008 how the steady state and stability models (base case R4) will translate the benchmarked events (R2)
into the models. At this point, there is no guidance on how to accomplish this goal of developing this type of models as well as conducting an
assessment to produce quality results.
SPP recommends the drafting team takes into consideration coordinating with the NERC RSTC and their liaisons to help develop a guideline that will
address uncharted territory applicable to the model build of this process.
The third and final concern relates to the expectations for the responsible entities to conduct an assessment from a library that does not currently exist.

We understand that EPRI is working with NERC to construct the library to support the requirement’s effort. However, we will find it difficult for the
responsible entities to support this requirement while there is no data to review. At this point, there is no official library data available for the responsible
entities to conduct an assessment as well as compare those results with other entities to ensure quality results have been produced.
SPP recommends that the drafting team coordinate with NERC staff and ensure that the library has been finalized before moving forward with this
requirement. It will be difficult to convince industry to support this effort when there are still too many unresolved issues at this point.

Likes

0

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0

Response
Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer

No

Document Name
Comment
Benchmark library that is used for the Assessment may be better maintained at a Regional level.
Likes

0

Dislikes

0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

No

Document Name
Comment
Tri-State supports the comments submitted by the MRO NSRF.
Likes

0

Dislikes

0

Response
Matt Lewis - Lower Colorado River Authority - 1
Answer
Document Name

No

Comment
LCRA TSC agrees with other comments in that we would like to see the PCs maintain the benchmark event data for the applicable region rather than
the data and library being entirely at one location under NERC control.
Likes

0

Dislikes

0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

No

Document Name
Comment
Minnesota Power supports MRO’s NERC Standards Review Forum’s (NSRF) comments.
Likes

0

Dislikes

0

Response
Teresa Krabe - Lower Colorado River Authority - 5
Answer

No

Document Name
Comment
LCRA agrees with other comments in that we would like to see the PCs maintain the benchmark event data for the applicable region rather than the
data and library being entirely at one location under NERC control.
Likes

0

Dislikes

0

Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Document Name
Comment

No

Based on the sample benchmark information and assumed footprints of TPs/PCs, there could be situations where multiple Extreme Temperature
Assessments may be needed to fully cover the risks posed. With the re-assessments required “at least once every five calendar years” should it be
expected that identification of individual and joint responsibilities should occur for each Extreme Temperature Assessment and re-assessment? Would
suggest removing the “or between departments of a vertically integrated system” as that would seem extremely limited in terms of actions needed to
perform an Extreme Temperature Assessment. If Company A is a PC and a TP the individual and joint responsibilities are assigned to Company A from
a compliance perspective. Requirement R2, as written, allows flexibility for PCs and TPs to select events best fitting their profile. The PCs will have to
use some judgement in Requirement R3 to coordinate individual TP events with the event selected by the PC.
Likes

0

Dislikes

0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

No

Document Name
Comment
Please see comments from EEI
Likes

0

Dislikes

0

Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment
EEI has no concerns with the updated Requirement R1. However, we continue to have concerns with Requirement R2 because this requirement relies
on an ERO developed benchmark library that is being developed without industry review and approval, and as of this draft we continue to only have
superficial insights into this library. Moreover, the ERO was directed to set a framework with this Reliability Standard that included specific bounds by
which the industry could conduct their extreme weather assessments. Yet, TPL-008-1 still does not contain any specific boundary limits that could
guide responsible entities in their Extreme Weather Assessments or otherwise limit what might be contained or added to the Extreme Weather Event
Library, now or in the future. For these reasons we ask that the DT set clear bounds that guide these Extreme Weather Assessments and set
boundaries for any future changes to the Extreme Weather Event Library. To address this concern, we suggest the following change in boldface below,
but have intentionally left the specific boundaries to be set by the DT:

R.2 Each responsible entity, as identified in Requirement R1, shall select at least one extreme heat benchmark temperature event and at least one
extreme cold benchmark temperature event for completing the Extreme Temperature Assessment. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]
2.1 Utilize metrological data that includes at least 20 years of historical data (or as determined by the DT), up to no less than two years
prior to the year the Extreme Temperature Assessment is started.
2.2

Reflect extreme temperature conditions with a specified probability of (As determined by the DT) within the responsible entity’s area.

2.3

Align extreme weather temperatures with those specified by all adjacent Planning Coordinators and Transmission Planners areas.

Likes

0

Dislikes

0

Response
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer

No

Document Name
Comment
Ameren agrees with and supports EEI's comments.
Likes

0

Dislikes

0

Response
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer

No

Document Name

TPL-008 Q2 Response.docx

Comment
PPL NERC Registered Affiliates agree with the general feedback provided by EEI. Throughout our responses we have provided additional, specific
feedback in an effort to assist the DT's work. We appreciate the work of the DT to address feedback received for R1-R2. We recommend changes in the
attached document to improve upon the revisions.
Likes

0

Dislikes
Response

0

Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment
Southern Company agrees with EEI’s comment.
Additionally, the R2 and M2 language should be revised to extreme heat/cold temperature benchmark event for consistency with other mentions of
‘temperature benchmark events’, as opposed to ‘benchmark temperature events’. This verbiage should be propagated consistently through the
standard.
Likes

0

Dislikes

0

Response
Junji Yamaguchi - Hydro-Quebec (HQ) - 5
Answer

No

Document Name
Comment
1. Similar to Attachment 1 of TPL-007-4, we suggest that the standard includes an attachment that contains the extreme heat and extreme cold
benchmark events. This is needed because stakeholders should have the opportunity to review the list of events and understand how they apply to
their region, and what assessments they would need to conduct ahead of being asked to approve this standard.
2.
Are the benchmark events considering regional-specific extremes? We are interested in seeing how Canadian, provincial attributes are considered
within the ERO benchmark library. It is extremely important that Canadian benchmarks are adequately reflected and/or provide flexibility for Canadian
entities to make appropriate changes to the ERO benchmark library.
Likes

0

Dislikes

0

Response
Richard Vendetti - NextEra Energy - 5
Answer
Document Name
Comment
NextEra supports EEI's comments

No

EEI has no concerns with the updated Requirement R1. However, we continue to have concerns with Requirement R2 because this requirement relies
on an ERO developed benchmark library that is being developed without industry review and approval, and as of this draft we continue to only have
only superficial insights into this library. Moreover, the ERO was directed to set a framework with this Reliability Standard that included specific bounds
by which the industry could conduct their extreme weather assessments. Yet, TPL-008-1 still does not contain any specific boundary limits that could
guide responsible entities in their Extreme Weather Assessments or otherwise limit what might be contained or added to the Extreme Weather Event
Library, now or in the future. For these reasons we ask that the DT set clear bounds that guide these Extreme Weather Assessments and set
boundaries for any future changes to the Extreme Weather Event Library. To address this concern, we suggest the following change in boldface below,
but have intentionally left the specific boundaries to be set by the DT:

R.2 Each responsible entity, as identified in Requirement R1, shall select at least one extreme heat benchmark temperature event and at least one
extreme cold benchmark temperature event, from the benchmark library, approved and maintained by the Electric Reliability Organization
(ERO), for completing the Extreme Temperature Assessment. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
2.1 Utilize metrological data that includes at least 20 years of historical data (or as determined by the DT), up to no less than two years
prior to the year the Extreme Temperature Assessment is started.
1.2

Reflect extreme temperature conditions with a specified probability of (As determined by the DT) within the responsible entity’s area.

1.3

Align extreme weather temperatures with those specified by all adjacent Planning Coordinators and Transmission Planners areas.

Likes

0

Dislikes

0

Response
Kevin Conway - Western Power Pool - 4
Answer

No

Document Name
Comment
Would like to see a more concrete Benchmark Event Library functioning.
Likes

0

Dislikes

0

Response
Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer
Document Name

No

Comment
For R2, Santee Cooper is concerned with the extreme heat and cold benchmark temperature being selected from a benchmark library that is approved
and maintained by the Electric Reliability Organization (ERO). This may be better coordinated, assessed and planned at the Regional level. Being able
to access and review the library before approving the requirement would be helpful.
Likes

0

Dislikes

0

Response
Amy Wilke - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
ATC supports the MRO NSRF comments.
Likes

0

Dislikes

0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

No

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and the Midwest Reliability Organization's NERC
Standards Review Forum (MRO NSRF) on question 2
Likes

0

Dislikes

0

Response
Barbara Marion - Dominion - Dominion Resources, Inc. - 5, Group Name Dominion
Answer
Document Name

No

Comment
There are concerns over the CAP as well as ambiguity in R2.
Likes

0

Dislikes

0

Response
Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
Focusing exclusively on temperature will not get the job done; combinations of weather threats must be studied. What made Winter Storm Uri so
destructive was that it began with an ice storm, taking-out the wind fleet of northern Texas, followed by a deep freeze with high winds, then a wind
drought. The Polar Vortex of 2014 was preceded by drenching rain, which soaked insulation and made generation units vulnerable to the combination
of low temperatures and high winds that followed.
Likes

0

Dislikes

0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

No

Document Name
Comment
SMUD supports the comments submitted by the MRO NSRF.
Likes

0

Dislikes

0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

No

Document Name
Comment
Black Hills Corporation has no concerns with the updated requirement R1 language. However, Black Hills Corporation has concerns with requirement
R2 and echoes the comments developed by EEI, which are in italics below. Black Hills Corporation is concerned with the limited visibility and
subsequent review by industry of the benchmark library being developed by the ERO.
‘[W]e continue to have concerns with Requirement R2 because this requirement relies on an ERO developed benchmark library that is being developed
without industry review and approval, and as of this draft we continue to only have only superficial insights into this library. Moreover, the ERO was
directed to set a framework with this Reliability Standard that included specific bounds by which the industry could conduct their extreme weather
assessments. Yet, TPL-008-1 still does not contain any specific boundary limits that could guide responsible entities in their Extreme Weather
Assessments or otherwise limit what might be contained or added to the Extreme Weather Event Library, now or in the future. For these reasons we
ask that the DT set clear bounds that guide these Extreme Weather Assessments and set boundaries for any future changes to the Extreme Weather
Event Library. To address this concern, we suggest the following change in boldface below, but have intentionally left the specific boundaries to be set
by the DT:
R.2 Each responsible entity, as identified in Requirement R1, shall select at least one extreme heat benchmark temperature event and at least one
extreme cold benchmark temperature event (remove:, from the benchmark library, approved and maintained by the Electric Reliability
Organization (ERO)), for completing the Extreme Temperature Assessment. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
2.1 Utilize metrological data that includes at least 20 years of historical data (or as determined by the DT), up to no less than two years
prior to the year the Extreme Temperature Assessment is started.
2.1.

Reflect extreme temperature conditions with a specified probability of (As determined by the DT) within the responsible entity’s area.

2.2.

Align extreme weather temperatures with those specified by all adjacent Planning Coordinators and Transmission Planners areas.’

Likes

0

Dislikes

0

Response
Robert Jones - Seattle City Light - 1,3,4,5,6
Answer

No

Document Name
Comment
It is difficult to evaluate this requirement without a functioning Benchmark Event Library or a far more explicit description of what will be included in the
library.
Likes

0

Dislikes
Response

0

Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

No

Document Name
Comment
Oncor would like to ensure transparency in how the benchmark events are developed, chosen, calculated, and maintained. We agree with other’s
comments in that we would like to see the PCs maintain the benchmark event data for the applicable region rather than the data and library being
entirely at one location under NERC control. This approach would likely make the data more transparent and accessible to the affected utilities than
having a sole central repository at NERC for all regions of the country. In addition, the PC is likely to have more specific knowledge about effective
methods of tuning and modifying the cases than NERC staff.
Likes

0

Dislikes

0

Response
Daniel Gacek - Exelon - 1
Answer

No

Document Name
Comment
R1 – Exelon does not have any objections to the proposed language for Requirement R1.
R2 – Exelon believes it is not appropriate to assign the Electric Reliability Organization (ERO) responsibility within the standard requirement that directly
impacts the compliance to the standard requirement. There is a compliance risk to the directly assigned entity if the ERO fails to uphold its responsibility
to maintain the database. We suggest coordinating this the way MMWG is coordinated through ERAG in the Eastern Interconnection.
Additionally, Exelon supports the comments submitted by the EEI for this question.

Likes

0

Dislikes

0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer
Document Name
Comment

No

Like Attachment 1 of TPL-007-4, we suggest that the standard includes an attachment that contains the extreme heat and extreme cold benchmark
events. This is needed because stakeholders should have the opportunity to review the list of events and understand how they apply to their region,
and what assessments they would need to conduct ahead of being asked to approve this standard.
Are the benchmark events considering regional-specific extremes? We are interested in seeing how Canadian, provincial attributes are considered
within the ERO benchmark library. It is extremely important that Canadian benchmarks are adequately reflected and/or provide flexibility for Canadian
entities to make appropriate changes to the ERO benchmark library.
Likes

0

Dislikes

0

Response
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

No

Document Name
Comment
The MRO NSRF supports some of the revisions and proposes modifications to others as detailed below.

R1. The MRO NSRF supports the SDT’s decision to shorten the language to “completing.”
R2. R2 and R4 need to be adjacent to each other as they both describe necessary cases. One should not have to read through R6 to know dynamic
cases are also required.
Likes

1

Dislikes

Scott Brame, N/A, Brame Scott
0

Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
Dominion Energy supports EEI comments
Likes

0

Dislikes
Response

0

Zahid Qayyum - New York Power Authority - 5
Answer

No

Document Name
Comment
• NYPA Disagrees with R2 stating ‘benchmark library, approved and maintained by the Electric Reliability Organization (ERO)’. We believe that for
greater effectiveness and suitability, the responsibility for maintaining and updating the library should be emphasized at the regional entity level rather
than the ERO to better incorporate regional variability.
• Is the use of “category P0” to describe normal system condition in R1 appropriate, given that it includes both benchmark and extreme events,
which are not typically considered normal operating conditions?

Likes

0

Dislikes

0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

No

Document Name
Comment
FirstEnergy supports EEI’s comments which state:
EEI has no concerns with the updated Requirement R1. However, we continue to have concerns with Requirement R2 because this requirement relies
on an ERO developed benchmark library that is being developed without industry review and approval, and as of this draft we continue to only have
superficial insights into this library. We also do not agree that ERO responsibilities and obligations need to be stated in the Requirement. To address
this concern, we suggest the following change in boldface below:
R.2 Each responsible entity, as identified in Requirement R1, shall select at least one extreme heat benchmark temperature event and at least one
extreme cold benchmark temperature event, from the Extreme Weather Event Library, for completing the Extreme Temperature Assessment.
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
2.1 Utilize metrological data that includes at least 20 years of historical data (or as determined by the DT), up to no less than two years prior to the year
the Extreme Temperature Assessment is started.
2.2 Reflect extreme temperature conditions with a specified probability of (As determined by the DT) within the responsible entity’s area.
2.3 Align extreme weather temperatures with those specified by all adjacent Planning Coordinators and Transmission Planners areas.

Likes

0

Dislikes

0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

No

Document Name
Comment
Duke Energy agrees with and recommends implementation of EEI comments. Additionally, the standard language ERO developed benchmark library
should be deleted and the concept of an entity standardized benchmark library should be developed, maintained, and remain with local or regional
responsible entities (e.g., TP/PC).
Likes

0

Dislikes

0

Response
Fon Hiew - NB Power Corporation - New Brunswick Power Transmission Corporation - 5
Answer

No

Document Name
Comment
Like Attachment 1 of TPL-007-4, we suggest that the standard includes an attachment that contains the extreme heat and extreme cold benchmark
events. This is needed because stakeholders should have the opportunity to review the list of events and understand how they apply to their region,
and what assessments they would need to conduct ahead of being asked to approve this standard.
Are the benchmark events considering regional-specific extremes? We are interested in seeing how Canadian, provincial attributes are considered
within the ERO benchmark library. It is extremely important that Canadian benchmarks are adequately reflected and/or provide flexibility for Canadian
entities to make appropriate changes to the ERO benchmark library.
Likes

0

Dislikes

0

Response
Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer

No

Document Name
Comment
Comments:
1.
Similar to Attachment 1 of TPL-007-4, we suggest that the standard includes an Attachment 1 that contains a list or examples of the extreme heat
and extreme cold benchmark events. This is required to avoid confusion because stakeholders need to know how and what assessments they need to
ensure applicability to their region when the standard is posted for approval.
2.
Are the benchmark events considering regional-specific extremes? We are interested in seeing how Canadian, provincial attributes are considered
within the ERO benchmark library. It is extremely important that Canadian benchmarks are adequately reflected and provide flexibility for Canadian
jurisdictions to make appropriate changes to the ERO benchmark library.
Likes

0

Dislikes

0

Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
(R1) No issues.
(R2) Due to R2 referencing a benchmark library that is not currently accessible, and therefore not fully understood, we are unable to express support for
this requirement. We recommend making accessible the benchmark temperature event library prior to seeking concurrence on a dependent
requirement.
Likes

0

Dislikes

0

Response
Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
For R2: Technical Rationale states that “The ERO will maintain a library of benchmark events and develop a process to incorporate additional events
proposed by responsible entities.” The standard does not provide any mechanism for responsible entities to propose events or collaborate on the review
or approval process. As we commented before, this gives the ERO the ability to change compliance requirements at will (by changing or removing
approved benchmark events) without going through any of the usual industry collaboration process. This standard should have a requirement for the

ERO to coordinate with Planning Coordinators to identify the benchmark events, or require the Planning Coordinators to collectively identify benchmark
events in collaboration with the ERO and have the ERO simply provide a place to host the information.
Likes

0

Dislikes

0

Response
Chelsea Loomis - Western Power Pool - NA - Not Applicable - WECC, Group Name WPP Consortium of Engineers
Answer

No

Document Name
Comment
Would like to see a more concrete Benchmark Event Library functioning.
Likes

0

Dislikes

0

Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer

No

Document Name
Comment
While the drafting team made adjustments in an attempt to address concerns with the proposed benchmark library, R2 continues to leave this standard
and the extreme temperature events open to broad adjustment without guaranteed stakeholder input. NERC has outlined a draft weather event
development and maintenance process; however, this is a draft, and there is currently no process outlined for stakeholders to challenge the validity of
benchmark events. Stakeholders cannot vote to approve R2 to TPL-008 because this will create an undefined, unchecked path for changes to the
extreme temperature events, that are required to be assessed and planned for, without guaranteed stakeholder input and opportunity to challenge
changes to benchmark events.
Likes

0

Dislikes

0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer
Document Name

No

Comment
There should be an emphasis on Regional, not ERO. Not required for ERO to maintain this library, such libraries are better maintained at the Regional
level. For smaller utilities, not sure how they are using the same criteria for Extrement Temperature Assessment.
Likes

2

Dislikes

Snohomish County PUD No. 1, 3, Chaney Holly; Jennie Wike, N/A, Wike Jennie
0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer

No

Document Name
Comment
Like Attachment 1 of TPL-007-4, we suggest that the standard includes an attachment that contains the extreme heat and extreme cold benchmark
events. This is needed because stakeholders should have the opportunity to review the list of events and understand how they apply to their region,
and what assessments they would need to conduct ahead of being asked to approve this standard.
Are the benchmark events considering regional-specific extremes? We are interested in seeing how Canadian, provincial attributes are considered
within the ERO benchmark library. It is extremely important that Canadian benchmarks are adequately reflected and/or provide flexibility for Canadian
entities to make appropriate changes to the ERO benchmark library.
Likes

0

Dislikes

0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza
Answer

No

Document Name
Comment
1. Similar to Attachment 1 of TPL-007-4, we suggest that the standard includes an attachment that contains the extreme heat and extreme cold
benchmark events. This is needed because stakeholders should have the opportunity to review the list of events and understand how they apply to
their region, and what assessments they would need to conduct ahead of being asked to approve this standard.
2.
Are the benchmark events considering regional-specific extremes? We are interested in seeing how Canadian, provincial attributes are considered
within the ERO benchmark library. It is extremely important that Canadian benchmarks are adequately reflected and/or provide flexibility for Canadian
entities to make appropriate changes to the ERO benchmark library.
Likes

0

Dislikes

0

Response
Elizabeth Davis - Elizabeth Davis On Behalf of: Thomas Foster, PJM Interconnection, L.L.C., 2; - Elizabeth Davis
Answer

Yes

Document Name
Comment
PJM supports the IRC SRC comments.
Likes

0

Dislikes

0

Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
ERCOT joins the comments submitted by the ISO/RTO Council (IRC) Standards Review Committee (SRC) and adopts them as its own.
Likes

0

Dislikes

0

Response
Bobbi Welch - Midcontinent ISO, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee (SRC) Project 2023-07 TPL-008-1 Draft #2
Answer

Yes

Document Name
Comment
R1. The ISO/RTO Council Standards Review Committee (SRC)[1] supports the SDT’s decision to shorten the language to “completing.”
[1] For purposes of these comments, the IRC SRC includes the following entities: CAISO (except for our response re: Part 9.2 to question 5), ERCOT,
IESO (except for our response to question 5 in its entirety), ISO-NE, MISO, NYISO, PJM and SPP.
Likes

0

Dislikes

0

Response
Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer

Yes

Document Name
Comment
ISO-NE recommends that the SDT review areas where Requirements could be combined to simplify or clarify the flow of requirements. TPL-007 is an
example of how out of order requirements can confuse the industry, which required a flowchart in the technical rationale to illustrate the order in which
requirements are performed.
While ISO-NE appreciates the Benchmark Event Example, many concerns that the industry has regarding this standard and the studies that would be
required could be alleviated by the SDT/NERC providing a list of the Benchmark Temperature Events that would be available to choose from and what
parameters are included for each event. It is difficult for areas to determine what would be required and to agree to perform studies on specific events
without the list of events to choose from for the studies.
In the specific Benchmark Event Example, ISO-NE did not experience a cold weather event so there is no value in studying that particular event.
ISO-NE requests that a list of Benchmark Events be provided prior to any final Ballot on the TPL-008 Standard.
In addition, the requirements to coordinate between PCs could cause a burden on PCs if their neighbors choose to study a different Benchmark
Event. For example, the Benchmark Event Example of Winter Storm Elliot would not be an event ISO-NE would choose as it did not have a significant
impact on the ISO-NE area; However, PJM as the PC may choose to study it. If ISO-NE chooses the January 1998 Ice Storm, what effect would that
have on NYISO which is adjacent to both ISO-NE and PJM? Do they now have to coordinate with both for the separate studies? What if NYISO
chooses to study Polar Vortex in 2014?
Or, are we required to agree on a singular event to be studied? A line would need to be drawn somewhere. As in the case above, PJM wouldn’t benefit
from studying the 1998 Ice Storm and ISO-NE wouldn’t benefit from studying Winter Storm Elliot. If so, some PCs may need to create model data for
multiple Benchmark Events. In addition to possibly having to address multiple Events, some PCs may choose a different year (Year 6 through Year 10)
within the Long-Term Planning Horizon, which further increases the burden associated with coordinating studies between the PCs.
Likes

0

Dislikes

0

Response
Carver Powers - Utility Services, Inc. - 4
Answer
Document Name
Comment

Yes

We understand the urgency of these modifications directed by FERC in Order No. 896 and agree to the proposed modifications made by the standard
drafting team. However, it is challenging to agree due to not knowing the benchmarks to be set by NERC.
Likes

0

Dislikes

0

Response
Helen Lainis - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment
We understand from the SDT that the ERO is currently working on Canadian benchmarks. It is very important that Canadian benchmarks are
considered within the ERO benchmark library so that we can appropriately assess.
Likes

0

Dislikes

0

Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

Yes

Document Name
Comment
We don’t see any extreme temperature events identified for Canadian provinces. We assume NERC will reach out to applicable PCs/TPs to get the
initial list of benchmark events prior to December 2024 to prepare the benchmark list for the first five years (according to the draft ERO Enterprise
Process document for TPl-008-1).
Likes

0

Dislikes

0

Response
Apollonia Gonzales - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Ben Hammer - Western Area Power Administration - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Greg Sorenson - Greg Sorenson On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Greg Sorenson
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Israel Perez - Israel Perez On Behalf of: Laura Somak, Salt River Project, 3, 6, 5, 1; Mathew Weber, Salt River Project, 3, 6, 5, 1; Thomas
Johnson, Salt River Project, 3, 6, 5, 1; Timothy Singh, Salt River Project, 3, 6, 5, 1; - Israel Perez
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Michele Tondalo - United Illuminating Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Robert Follini - Avista - Avista Corporation - 3
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Ronald Hoover - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
As there are still unknowns regarding the Benchmark Event Library, BPA cannot make a determination on R2 at this time. Once BPA can review the
library, and attend the planned NERC training, BPA can review and provide more meaningful comments/feedback.
Likes

0

Dislikes

0

Response
Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer
Document Name
Comment
The text of Requirement #2 mentions “benchmark library, approved and maintained by the Electric Reliability Organization (ERO)”.
Similar to Attachment 1 of TPL-007-4, we recommend that the final version of the standard include an attachment that contains details of the extreme
heat and extreme cold benchmark events, or at least some mention of the public facing library (site) to be created by Q4 2024 (as mentioned in the
TPL-008 webinar in July 2024) and maintained by NERC. Ideally, stakeholders should have the opportunity to review the list of events and understand
how they apply to their region, and what assessments they would need to conduct ahead of being asked to approve this standard.
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3. The DT updated Requirements R3 – R5 based on comments received. Do you agree with the updated proposed TPL-008-1 Reliability
Standard Requirements R3-R5? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural
justification.
Long Island Power Authority

Answer

Yes

Document Name

(if an attachment is provided by submitter)

Comment
Requirement #5 mentions having criteria for acceptable System steady state voltage limits, post-Contingency voltage deviations,
and applicable Facility Ratings.
Is it the intent that entities will also have to have (and document) applicable thermal criteria for completing the Extreme
Temperature Assessment? For example, allowing for the possible use of STE facility ratings post-contingency?
In certain jurisdiction, extreme temperature ratings have been established, but that is not necessarily the case in all jurisdictions.
Will facility owners be required to establish extreme cold or warm temperature ratings for this standard?
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# of other submitters who agree with these comments

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# of other submitters who disagree with these comments

Response
(Drafting team’s response to submitter’s comments)
Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza
Answer

No

Document Name
Comment
We are concerned that the R3-R4 requirements may necessitate a significant coordination effort by each PC similar to the MMWG base case
development for the Eastern Interconnection for each of the extreme weather events. Was this the intent of R3-R4? If so, it does not seem feasible to
develop consistent wide-area cases when each PC can select unique events. We note that R4.1 gives the freedom for individual adjacent entities to
choose a different year for the long-term horizon, which could result in the requirement to develop even more cases. However, we agree with R5.
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Jeffrey Streifling - NB Power Corporation - 1
Answer

No

Document Name
Comment
We are concerned that the R3-R4 requirements may necessitate a significant coordination effort by each PC like the MMWG base case development
for the Eastern Interconnection for each of the extreme weather events. Was this the intent of R3-R4? If so, it does not seem feasible to develop
consistent wide-area cases when each PC can select unique events. We note that R4.1 gives the freedom for individual adjacent entities to choose a
different year for the long-term horizon, which could result in the requirement to develop even more cases. However, we agree with R5.
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Thomas Foltz - AEP - 5
Answer

No

Document Name
Comment
AEP is concerned by the phrase “at least one of the following conditions” within R4.2, as temperature would conceivably impact all three conditions
specified: “Generation”, “Real and reactive forecasted Load”, and “Transfers.” It follows then that using only one of these conditions could result in an
analysis that might not capture all potential reliability issues. AEP believes the Technical Rationale could benefit from additional insight regarding the
recommended conditions that might be considered for ensuring a high-quality analysis. AEP recommends revising the Technical Rationale document
accordingly.
AEP recommends to the SDT that care be taken to ensure that the obligations related to sensitivity cases align with the directives issued in FERC Order
1920.
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0

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Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer
Document Name
Comment

No

Need to define "other designated study entities" listed in R3. "Other designated study entities" is an unclear term. R5 Risk factor should be Medium to
match TPL 001-5. The significant level of coordination needed for the standard will be a concern, particularly for small utilities.
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2

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Snohomish County PUD No. 1, 3, Chaney Holly; Jennie Wike, N/A, Wike Jennie
0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

No

Document Name
Comment
R3: Base Case should include known outages.
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0

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Chelsea Loomis - Western Power Pool - NA - Not Applicable - WECC, Group Name WPP Consortium of Engineers
Answer

No

Document Name
Comment
“other designated study entities” is unclear. R5 Risk factor should be Medium to match TPL 001-5. Concern that level of coordination needed to effect
the standard will be significant, particularly for “smaller” entities.
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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Document Name
Comment

No

(R3) We recommend that R3 be updated to suggest that “designated study entities” are to be identified as part of the PC developed coordination
process and only required to be coordinated with if included in the PC developed process. Otherwise, the term “designation” may suggest (1) the
benchmark cases will designate entities, (2) entities other than the PC may designate a study entity, or (3) they may self-identify. It is unclear how the
designation process will occur and the scale of entities to be possibly included.
(R4.2) We do not agree that R4.2, which requires an increasingly more extreme scenario for purposes of a sensitivity analysis, is credible. This is
especially true for longer term planning horizons when generation additions and retirements, along with transmission configuration changes and new
technologies to be deployed are less detailed.
(R5) No issues.
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Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer

No

Document Name
Comment
Comments:
We are concerned that the R3-R4 requirements necessitate a coordination effort by each PC very similar to the MMWG base case development for the
Eastern Interconnection for each of the extreme weather events. Was this the intent of R3-R4? Please clarify. If so, it does not seem feasible to
develop consistent wide-area cases by each PC when a PC can select its own unique events. We note that R4.1 also gives the flexibility for adjacent
entities to choose a different year for the long-term horizon, which could result in the requirement to develop even more cases. This undertaking must
be simple and straightforward.
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Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

No

Document Name
Comment
CHPD believes the updates made to R3 through R5 were very good, with a couple concerns remaining. The statement ‘and other designated study
entities’, is unclear. What is a study entity? Who is doing the designating? Due to non-clarity, it is recommended NERC provide clarity here or remove
this language.

In addition, an R5 concern is the VRF for the limits criteria is ‘High’ as proposed in TPL-008, while the same type of limits requirement has a VRF of
‘Medium’ in TPL-001-5 R5. It is requested the VRF for TPL-008 R5 be similarly set as ‘Medium’ for consistency.
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1

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Jennie Wike, N/A, Wike Jennie
0

Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

No

Document Name
Comment
Manitoba Hydro does not think there is a need to perform additional sensitivity studies as per R 4.2. We think R4.1 is sufficient to develop base cases
capturing the sensitivity of generation, load, and transfers for extreme temperature events.
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Ronald Hoover - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA believes “other designated study entities” in R3 is unclear.
R4.1 – BPA recommends deleting the sentence "The rationale for the year selected for evaluation shall be available as supporting information" as it is
unclear what type(s) of rationale would be required. BPA views this as a potential for undue compliance burden on industry and will create difficulty
when providing compliance evidence artifacts."

BPA recommends the R5 Risk Factor should be set to Medium to match TPL 001-5. BPA is concerned that the level of coordination needed is not well
defined and will be very difficult for smaller entities.
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0

Fon Hiew - NB Power Corporation - New Brunswick Power Transmission Corporation - 5
Answer

No

Document Name
Comment
We are concerned that the R3-R4 requirements may necessitate a significant coordination effort by each PC like the MMWG base case development
for the Eastern Interconnection for each of the extreme weather events. Was this the intent of R3-R4? If so, it does not seem feasible to develop
consistent wide-area cases when each PC can select unique events. We note that R4.1 gives the freedom for individual adjacent entities to choose a
different year for the long-term horizon, which could result in the requirement to develop even more cases. However, we agree with R5.
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0

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Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

No

Document Name
Comment
FirstEnergy supports EEI’s comments which state:
EEI no concerns with the updated Requirement R1. However, we continue to have concerns with Requirement R2 because this requirement relies on
an ERO developed benchmark library that is being developed without industry review and approval, including the deadlines for the review of the
Extreme Temperature Assessments by adjacent PCs and TPs. To address our concerns, we offer the following in boldface for consideration:
R3.
Each Planning Coordinator shall develop and implement a process for developing benchmark planning cases, using the selected benchmark
temperature events identified in Requirement R2. The process shall include: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
3.1.
Seasonal and temperature dependent adjustments for Load, generation, Transmission, and transfers in the responsibility entity’s area
based on the extreme temperature conditions identified in Requirement R2.
3.2.1 Processes for requesting seasonal and temperature dependent adjustments for Load, generation, Transmission, and transfers from
the adjacent entity’s area based on the extreme temperature conditions identified in Requirement R2 that obligate the adjacent PC & TP to
respond within 6 months of the request.
3.2.2 Obligation to respond to notify any affected Planning Coordinators and Transmission Planners of any concerns within 120 days of
receipt of the data supplied.
3.2.3 An additional 60 shall also be allotted to the responsible Planning Coordinator to resolve any issues or concerns cited by the
adjacent Planning Coordinator or Transmission Planner.
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0

Zahid Qayyum - New York Power Authority - 5
Answer

No

Document Name
Comment
NYPA believes the term used in R3 “other designated study entities" is vague and requires clarification from the SDT for better understanding. The
significant level of coordination is needed for this Standard may be a concern, particularly for small utilities.
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Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

No

Document Name
Comment
The MRO NSRF’s most significant concerns involve requirements R3 and R4 as detailed below.
The Coordination Effort Required for Consistent, Wide-Area Cases Negates the Benefit of Choosing a Unique Benchmark Event
R3. While the MRO NSRF agrees the proposed language, “among adjacent impacted Planning Coordinator(s), Transmission Planner(s), and other
designated study entities,” is an improvement over the prior language because it clarifies how far an entity must reach beyond its footprint to satisfy the
requirement.

That said, the MRO NSRF still has significant concerns regarding the number of studies which must be performed, particularly when a Planning
Coordinator (PC) selects a benchmark temperature event that is different from that of its adjacent PC(s). In that situation, each benchmark temperature
event may necessitate a significant coordination effort, similar to what is done to develop the MMWG base case for the Eastern Interconnection.

If that’s the case, it doesn’t seem feasible to develop consistent, wide-area cases when each PC can select unique events. We also note that R4.1 gives
each entity the freedom to choose a different year for the long-term horizon, which could further exacerbate the number of cases that must be
developed to comply with the coordination process under R3.

To address this concern, the MRO NSRF recommends a governing body identify the scenarios. Extreme temperature events will typically extend
beyond the footprint of a single Planning Coordinator. To avoid putting the PCs in a position where they are required to agree on a scenario, a year and
the sensitivity to be studied, NERC or other (e.g. ERAG) should identify the extreme heat and extreme cold temperature events to be studied. This is
necessary for consistent modeling results across adjacent planning entities. Also, as a benchmark temperature event may extend across several

planning areas, the governing body must take this into consideration when determining which extreme heat and extreme cold temperature events are to
be studied so that no planning entity is assigned more than one of each.

R4. MRO NSRF supports the proposed language (“data consistent with that provided in accordance with the MOD-032 standard”) and does not see a
need to update MOD-032 at this time; however, depending upon what data the benchmark temperature event requires to perform the study, this may
need to be revisited.

Part 4.1 MRO NSRF supports Part 4.1 and views the benchmark temperature event as a “base case sensitivity” to that performed under TPL-001.

Part 4.2 Is there an opportunity to “bake” sensitivities into the benchmark temperature event?

R5. MRO NSRF supports the addition of “and applicable Facility Ratings” considering the need to comply with FERC Order 881 and Ambient Adjusted
Ratings in the near future. MRO NSRF is also exploring this further with its member TOs.
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Scott Brame, N/A, Brame Scott
0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer

No

Document Name
Comment
We are concerned that the R3-R4 requirements may necessitate a significant coordination effort by each PC like the MMWG base case development
for the Eastern Interconnection for each of the extreme weather events. Was this the intent of R3-R4? If so, it does not seem feasible to develop
consistent wide-area cases when each PC can select unique events. We note that R4.1 gives the freedom for individual adjacent entities to choose a
different year for the long-term horizon, which could result in the requirement to develop even more cases. However, we agree with R5.
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0

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Daniel Gacek - Exelon - 1
Answer
Document Name

No

Comment
There is nothing in the standard enforcing that PCs and TPs need to coordinate and share data between themselves to build the cases in R4. This may
need to be a stand-alone requirement. “Each responsible entity shall coordinate and cooperate with other responsible entities to create the benchmark
planning Cases.”
R3 – The last sentence needs clarification. Propose to change it to “This process shall include documentation of assumptions that consider seasonal
and temperature dependent adjustments for Load, generation, Transmission, and transfers to represent the selected benchmark temperature events.”
R4 – No concerns from Exelon.
R5 – No concerns from Exelon.
Additionally, Exelon supports the comments submitted by the EEI for this question.
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Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

No

Document Name
Comment
For R3, Oncor agrees with the idea that the PC should have the responsibility for coordinating and developing benchmark planning cases.
For R4, “Each responsible entity…” could be replaced with language that is similar to R3, and it would instead read “Each Planning Coordinator….”
Oncor also asks whether language can be added to ensure that entities can take credit for studies that are run as part of the Sensitivity analysis, rather
than running those studies again as part of the assessment to be conducted under TPL-001? For example, the Extreme Temperature Assessment
could take the place of the sensitivity analysis required within the TPL-001 assessment for both the steady state and stability analyses.Moreover, if the
Extreme Temperature Assessment is essentially a type of sensitivity analysis already, Oncor would advise removing R4.2 because this would create a
sensitivity case based on a sensitivity case.
For R5, Oncor urges its comment from R4, particularly because the PC would develop and maintain the criteria for acceptable System steady state
voltage limits and post-Contingency voltage deviations.
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Robert Jones - Seattle City Light - 1,3,4,5,6
Answer
Document Name

No

Comment
The term “other designated study entities” is unclear.
R5 Risk factor should be Medium to match TPL-001-5.
The level of coordination needed to comply with the standard will be significant, particularly for “smaller” entities.
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Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

No

Document Name
Comment
Black Hills Corporation has no concerns with the updated language for requirements R4 and R5. Black Hills Corporation has concerns with R3 and
aligns with the comments (below in italics) made by EEI with regards to requirement R3.
‘Requirement R3 does not provide sufficient clarity for the processes or expectations for coordination between adjacent Planning Coordinators and
Transmission Planners, including the deadlines for the review of the Extreme Temperature Assessments by adjacent PCs and TPs. To address our
concerns, we offer the following in boldface for consideration:
R3.
Each Planning Coordinator shall develop and implement a process for developing (remove: coordinating the development of) benchmark
planning cases, using the selected benchmark temperature events identified in Requirement R2. The process shall include: (remove: , among
adjacent impacted Planning Coordinator(s). Transmission Planner(s), and other designated study entities, within an Interconnection. This
process shall include seasonal and temperature dependent adjustments for Load, generation, Transmission, and transfers to represent the
selected benchmark temperature events.) [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
3.1. Seasonal and temperature dependent adjustments for Load, generation, Transmission, and transfers in the responsibility entity’s area
based on the extreme temperature conditions identified in Requirement R2.
3.2.1 Processes for requesting seasonal and temperature dependent adjustments for Load, generation, Transmission, and transfers from
the adjacent entity’s area based on the extreme temperature conditions identified in Requirement R2 that obligate the adjacent PC & TP to
respond within 6 months of the request.
3.2.2 Obligation to respond to notify any affected Planning Coordinators and Transmission Planners of any concerns within 120 days of
receipt of the data supplied.
3.2.3 An additional 60 shall also be allotted to the responsible Planning Coordinator to resolve any issues or concerns cited by the adjacent
Planning Coordinator or Transmission Planner.’
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0

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0

Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

No

Document Name
Comment
SMUD supports the comments submitted by the MRO NSRF regarding Requirement R4, Part 4.2 and recommends that Part 4.2 be removed in its
entirety.
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0

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Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
PCs can model benchmark events only if having valid sensitivity factors for temperature, wind speed and precipitation. They do not presently have this
information, and TPL-008-1 makes no suggestions in this respect other than that they refer to, “other sources as needed.” These sources are nonexistent.
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Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

No

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and the Midwest Reliability Organization's NERC
Standards Review Forum (MRO NSRF) on question 3
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Amy Wilke - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
ATC appreciates the additional clarity added to the relationship between R3 and R4.
ATC supports the MRO NSRF comments.
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Response
Kevin Conway - Western Power Pool - 4
Answer

No

Document Name
Comment
“other designated study entities” is unclear. R5 Risk factor should be Medium to match TPL 001-5. Concern that level of coordination needed to effect
the standard will be significant, particularly for “smaller” entities.
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0

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0

Response
Richard Vendetti - NextEra Energy - 5
Answer

No

Document Name
Comment
NextEra supports EEI's comments
EEI does not have concerns with the updated proposed Requirements for R4 and R5, however, Requirement R3 does not provide sufficient clarity for
the processes or expectations for coordination between adjacent Planning Coordinators and Transmission Planners, including the deadlines for the

review of the Extreme Temperature Assessments by adjacent PCs and TPs. To address our concerns, we offer the following in boldface for
consideration:

R3.
Each Planning Coordinator shall develop and implement a process for developing coordinating the development of benchmark planning
cases, using the selected benchmark temperature events identified in Requirement R2. The process shall include: , among adjacent impacted
Planning Coordinator(s). Transmission Planner(s), and other designated study entities, within an Interconnection. This process shall include
seasonal and temperature dependent adjustments for Load, generation, Transmission, and transfers to represent the selected benchmark
temperature events. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
3.1. Seasonal and temperature dependent adjustments for Load, generation, Transmission, and transfers in the responsibility entity’s area
based on the extreme temperature conditions identified in Requirement R2.
3.2.1 Processes for requesting seasonal and temperature dependent adjustments for Load, generation, Transmission, and transfers from
the adjacent entity’s area based on the extreme temperature conditions identified in Requirement R2 that obligate the adjacent PC & TP to
respond within 6 months of the request.
3.2.2 Obligation to respond to notify any affected Planning Coordinators and Transmission Planners of any concerns within 120 days of
receipt of the data supplied.
3.2.3 An additional 60 shall also be allotted to the responsible Planning Coordinator to resolve any issues or concerns cited by the adjacent
Planning Coordinator or Transmission Planner.

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0

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0

Response
Junji Yamaguchi - Hydro-Quebec (HQ) - 5
Answer

No

Document Name
Comment
We are concerned that the R3-R4 requirements may necessitate a significant coordination effort by each PC similar to the MMWG base case
development for the Eastern Interconnection for each of the extreme weather events. Was this the intent of R3-R4? If so, it does not seem feasible to
develop consistent wide-area cases when each PC can select unique events. We note that R4.1 gives the freedom for individual adjacent entities to
choose a different year for the long-term horizon, which could result in the requirement to develop even more cases. However, we agree with R5.
Likes

0

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0

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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company

Answer

No

Document Name
Comment
Southern Company appreciates the inclusion of ‘among adjacent’ as well as the clarification of what impacts will be considered in the development of
benchmark planning cases in R3; however, the expectations of coordination need further definition along with clarifying the timeline of coordination with
adjacent entities to prevent other entities from causing compliance risk.
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0

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0

Response
Helen Lainis - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment
We support NPCC TFCP comments. We are concerned that the coordination effort required for consistent, wide-area cases negates the
benefit of choosing a unique benchmark event. Specifically, we are concerned regarding the number of studies which must be performed,
particularly when a Planning Coordinator (PC) selects a benchmark temperature event that is different from that of its adjacent PC(s). In that
situation, each benchmark temperature event may necessitate a significant coordination effort, similar to what is done to develop the MMWG
base case for the Eastern Interconnection. It does not seem feasible to develop consistent, wide-area cases when each PC can select unique
events.

Consequently, we recommend that NERC/Regional Entities/ERAG to identify the scenarios, and the extreme heat and extreme cold
temperature events to be studied so that no planning entity is assigned more than one of each.
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Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment

No

Regarding Requirement R3, the DT has made improvements in this Requirement, but the language still fails to provide the flexibility necessary for a
responsible entity to get the required cases built in a timely and practical manner. There are two primary issues for which we provide recommendations
to provide more flexibility.
First, there is no specification or bounds on the type of data that represents the benchmark event. Is it a single temperature for the adjacent entity’s
entire region? Is it sub-zip-code level temperature data? Again, the DT must include more specifics in the standard about the framework and criteria of
benchmark temperature events.
Second, there is no flexibility to make technically justified assumptions. These will be necessary for this process to be completed effectively. Consider a
case with a local cold front. The responsible entity and all adjacent entities are experiencing increased load and potentially some lost generation. Thus,
they have a collective power deficit. How is this model going to solve? The power must be imported from somewhere. The DT should solve these issues
by allowing the responsible entity to make technically justified assumptions for non-adjacent areas. To continue the example above, if the entity is in the
northeast United States, it may reasonably assume power will be imported from the southern United States. It is not necessary to coordinate with all
entities to determine what imports will be available. As noted above, the impact of adjusting specific assets is diluted relative to electrical distance.
The two issues above would be appropriately addressed in the Requirement R2 and R3 proposed in the last question. Requirement R3 is repeated
here:
R3. Each responsible entity, as identified in Requirement R1, shall develop a process for developing benchmark planning cases to represent the
benchmark temperature events selected in Requirement R2. The process shall include:
3.1. Seasonal and temperature dependent adjustments for Load, generation, Transmission, and transfers in the responsibility entity’s area based on the
temperature conditions identified in Requirement R2 Part 2.2.
3.2. Coordination with adjacent Planning Coordinators and Transmission Planners to make seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers and in their areas based on the temperature conditions identified in Requirement R2 Part 2.3.
3.3. Technical rationale and methods for approximating seasonal and temperature dependent adjustments for Load, generation, Transmission, and
transfers in other areas of the Interconnection.
Finally, it is not clear who “other designated study entities” are. This should be removed or clarified by the DT (this phrase was removed in the
suggested language above).
Regarding Requirement R4, this format is improved from the first draft. However, it is recommended that the DT clarify in Part 4.2 that only one
sensitivity case is required for each benchmark temperature event. Suggested modification to the first sentence: “At least one s[S]ensitivity case[s] for
each benchmark planning case developed in Requirement R4 Part 4.1 to demonstrate the impact…”
The DT should also add a requirement specifying how much time adjacent entities have to submit data to a requestor. Suppose an entity starts its
Extreme Temperature Assessment six months before its due date. They request data from a neighbor and the neighbor does not provide the requested
data until 9 months later. Is the responsible entity to blame for not providing enough time? Or did the adjacent entity take too long?
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Michele Tondalo - United Illuminating Co. - 1
Answer
Document Name

No

Comment
In R3 it is not clear what this coordination between PCs is expected to result in, in particular how are adjacent regions that select different extreme
events expected to reconcile differences?
In R4.1, it is unclear what is establishing Category P0 as the normal System Condition in Table 1.
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Israel Perez - Israel Perez On Behalf of: Laura Somak, Salt River Project, 3, 6, 5, 1; Mathew Weber, Salt River Project, 3, 6, 5, 1; Thomas
Johnson, Salt River Project, 3, 6, 5, 1; Timothy Singh, Salt River Project, 3, 6, 5, 1; - Israel Perez
Answer

No

Document Name
Comment
Define Table 1 for requirement 4.1. Recommend clarifying on case selection for requirement R4.
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0

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Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer

No

Document Name
Comment
Ameren would like clarity on why R4.2 does not include Transmission. In addition, Ameren agrees with and supports EEI's comments.
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0

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Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name

No

Comment
EEI does not have concerns with the updated proposed Requirements for R4 and R5, however, Requirement R3 does not provide sufficient clarity for
the processes or expectations for coordination between adjacent Planning Coordinators and Transmission Planners, including the deadlines for the
review of the Extreme Temperature Assessments by adjacent PCs and TPs. To address our concerns, we offer the following in boldface for
consideration:

R3.
Each Planning Coordinator shall develop and implement a process for developing benchmark planning cases, using the selected benchmark
temperature events identified in Requirement R2. The process shall include: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
3.1. Seasonal and temperature dependent adjustments for Load, generation, Transmission, and transfers in the responsibility entity’s area
based on the extreme temperature conditions identified in Requirement R2.
3.2.1 Processes for requesting seasonal and temperature dependent adjustments for Load, generation, Transmission, and transfers from
the adjacent entity’s area based on the extreme temperature conditions identified in Requirement R2 that obligate the adjacent PC & TP to
respond within 6 months of the request.
3.2.2 Obligation to respond to notify any affected Planning Coordinators and Transmission Planners of any concerns within 120 days of
receipt of the data supplied.
3.2.3 An additional 60 shall also be allotted to the responsible Planning Coordinator to resolve any issues or concerns cited by the adjacent
Planning Coordinator or Transmission Planner.
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Selene Willis - Edison International - Southern California Edison Company - 5
Answer

No

Document Name
Comment
Please see comments from EEI
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Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Document Name

No

Comment
Is the coordination process expected to call out which year of “one of the years in the Long-Term Transmission Planning Horizon” is to be used? Or is
every year in the Long-Term Planning Horizon a coordinated effort? Or does each TP and PC select their own year (which would likely lead to possible
misleading overall results)?
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Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

No

Document Name
Comment
Minnesota Power supports MRO’s NERC Standards Review Forum’s (NSRF) comments.
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Greg Sorenson - Greg Sorenson On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Greg Sorenson
Answer

No

Document Name
Comment
R4, states that the sensitivity analysis shall include, at a minimum, changes to one of the following conditions: Generation; Real and reactive forecasted
Load; or Transfers. RF believes that the assessment should consider all of the listed conditions as opposed to only one. In the Feb 2021 Southwest
event, the load was higher and the generation lower than expected(https://www.ercot.com/news/february2021). Likewise, in the Dec 2022 Elliott event,
PJM load was significantly higher (10,000MW) while generation outages were significantly above baseline (https://www.pjm.com/-/media/library/reportsnotices/special-reports/2023/20230717-winter-storm-elliott-event-analysis-and-recommendation-report.ashx).
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Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

No

Document Name
Comment
Tri-State supports the comments submitted by the MRO NSRF.
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Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

No

Document Name
Comment
In R4.1, it is unclear what is establishing Category P0 as the normal System Condition in Table 1.
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Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer

No

Document Name
Comment
The "other designated study entities" mentioned in R3 need to be defined. The phrase "other designated study entities" is unclear.
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Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer
Document Name
Comment

No

SPP raises concerns regarding the coordination among neighboring entities impacted by Requirement R3. We understand that this coordination
extends to all Planning Coordinators, including those outside the event area, potentially leading to unnecessary administrative burdens. Moreover,
there is the concern of including/translating the seasonal and temperature dependent adjustments in the models. As we state in the previous question,
there is no guidance on how to accomplish this goal of developing this type of models as well as conducting an assessment to produce quality results.
SPP recommends the drafting team takes into consideration coordinating with the NERC RSTC and their liaisons to help develop a guideline that will
address uncharted territory applicable to the neighbor coordinating and model building process.
Regarding Requirement R4 and the use of the MOD-032 Standard for data collection, SPP questions its suitability for assessing Inverter-Based,
Distributed Energy, and Energy Storage Resources, given unresolved project directives.
At this point, SPP recommends that the drafting team coordinates with the drafting team Project 2022-02 (which includes MOD-032 efforts). This
coordination will ensure that the appropriate data request requirements are addressed as this will contribute the quality results from all associated
assessments.
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Kinte Whitehead - Exelon - 3
Answer

No

Document Name
Comment
There is nothing in the standard enforcing that PCs and TPs need to coordinate and share data between themselves to build the cases in R4. This may
need to be a stand-alone requirement. “Each responsible entity shall coordinate and cooperate with other responsible entities to create the benchmark
planning Cases.”
R3 – The last sentence needs clarification. Propose to change it to “This process shall include documentation of assumptions that consider seasonal
and temperature dependent adjustments for Load, generation, Transmission, and transfers to represent the selected benchmark temperature events.”
R4 – No concerns from Exelon.
R5 – No concerns from Exelon.
Additionally, Exelon supports the comments submitted by the EEI for this question.

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Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford

Answer

No

Document Name
Comment
R3:

•
•
•

Replace “Each Planning Coordinator shall” with “Each responsible entity, as identified in Requirement R1, shall”. This may require
supplemental wording edits in the requirement.
The inclusion of “other designated study entities” is not clear.
The SDT should consider combining this requirement with R4.
Requiring each PC to coordinate the development of benchmark planning cases among “adjacent impacted” entities “within an Interconnection”
is potentially a massive amount of workload as benchmark events may be significantly different between these entities. It is not reasonable for
the PC or TP to have responsibility for coordinating models outside of their respective planning areas.

•

The SDT should consider combining this requirement with R3.

•

The recently adopted NERC Glossary term, System Voltage Limits, should be referenced in this requirement instead of the outdated wording
“System steady state voltage limits”. “…shall have criteria for acceptable System Voltage Limits for performing the Extreme Temperature
Assessment…”
Since this requirement appears to refer to steady-state voltage, the post contingency voltage deviation portion of the existing requirement
should be removed. The resultant steady-state voltage level being outside of acceptable high and low limits is the point of concern. For
example, if a low voltage criterion is 0.92 p.u., then voltages below this limit would violate this particular criterion regardless of whether the
beginning voltage was 0.95 p.u., 0.98 p.u., or any other voltage level.
The inclusion of Facility Ratings in the requirement is not clear and does not offer an improvement over the previous draft. Since this standard
is modeling so much of its wording and the attached table after TPL-001, the performance criteria regarding ratings, voltage, & stability should
be similarly referenced in this standard. Note that “Performance Requirements” is more generally referred to in this draft’s R9 which could easily
refer to the suggested inclusion in the table. As it stands, “Performance Requirements” referred to in this draft is not clearly defined.

•

R4:

R5:

•

•

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Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

No

Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments:
We are concerned that the R3-R4 requirements may necessitate a significant coordination effort by each PC like the MMWG base case development
for the Eastern Interconnection for each of the extreme weather events. Was this the intent of R3-R4? If so, it does not seem feasible to develop

consistent wide-area cases when each PC can select unique events. We note that R4.1 gives the freedom for individual adjacent entities to choose a
different year for the long-term horizon, which could result in the requirement to develop even more cases. However, we agree with R5.
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Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer

No

Document Name
Comment
The requirements to coordinate between PCs could cause a burden on PCs if their neighbors choose to study a different Benchmark Event. For
example, the Benchmark Event Example of Winter Storm Elliot would not be an event ISO-NE would choose as it did not have a significant impact on
the ISO-NE area; However, PJM as the PC may choose to study it. If ISO-NE chooses the January 1998 Ice Storm, what effect would that have on
NYISO which is adjacent to both ISO-NE and PJM? Do they now have to coordinate with both for the separate studies? What if NYISO chooses to
study Polar Vortex in 2014?
Or, are we required to agree on a singular event to be studied? A line would need to be drawn somewhere. As in the case above, PJM wouldn’t benefit
from studying the 1998 Ice Storm and ISO-NE wouldn’t benefit from studying Winter Storm Elliot. If so, some PCs may need to create model data for
multiple Benchmark Events. In addition to possibly having to address multiple Events, some PCs may choose a different year (Year 6 through Year 10)
within the Long-Term Planning Horizon, which further increases the burden associated with coordinating studies between the PCs.
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Ben Hammer - Western Area Power Administration - 1
Answer

No

Document Name
Comment
WAPA has concerns regarding the number of studies which must be performed, particularly when a Planning Coordinator (PC) selects a benchmark
temperature event that is different from that of its adjacent PC(s). In that situation, each benchmark temperature event may necessitate a significant
coordination effort.

WAPA recommends a governing body identify the scenarios. Extreme temperature events will typically extend beyond the footprint of a single Planning
Coordinator. To avoid putting the PCs in a position where they are required to agree on a scenario, a year and the sensitivity to be studied, NERC or
other (e.g. ERAG) should identify the extreme heat and extreme cold temperature events to be studied. This is necessary for consistent modeling
results across adjacent planning entities. Also, as a benchmark temperature event may extend across several planning areas, the governing body must

take this into consideration when determining which extreme heat and extreme cold temperature events are to be studied so that no planning entity is
assigned more than one of each.
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Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

No

Document Name
Comment
Does the DT believe the existing MOD-032 includes the ability for both the TP and PCs to be able to obtain the information necessary from generators?
ITC understands the FERC requirement to perform a sensitivity study. ITC does believe the scope of work required for the sensitivity study should be
revised to make it more meaningful and so that it does provide a reliability benefit.
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Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CEHE agrees with EEI comments, requirement R3 does not provide sufficient clarity for the processes or expectations for coordination between
adjacent Planning Coordinators and Transmission Planners, including the deadlines for the review of the Extreme Temperature Assessments by
adjacent PCs and TPs.
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Bobbi Welch - Midcontinent ISO, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee (SRC) Project 2023-07 TPL-008-1 Draft #2
Answer
Document Name
Comment

No

The SRC’s most significant concerns involve requirement R3 as detailed below.
The Coordination Effort Required for Consistent, Wide-Area Cases Negates the Benefit of Choosing a Unique Benchmark Event
R3. The SRC agrees the proposed language, “among adjacent impacted Planning Coordinator(s), Transmission Planner(s), and other designated
study entities, within an Interconnection” is an improvement over the prior language because it clarifies how far an entity must reach beyond its footprint
to satisfy the requirement.
That said, the SRC still has significant concerns regarding the number of studies that must be performed, particularly when a Planning Coordinator (PC)
selects a benchmark temperature event that is different from that of its adjacent PC(s). In that situation, each benchmark temperature event may
necessitate a significant coordination effort, similar to what is done to develop the MMWG base case for the Eastern Interconnection.
If that’s the case, it doesn’t seem feasible to develop consistent, wide-area cases when each PC can select unique events. We also note that R4.1 gives
each entity the freedom to choose a different year for the long-term horizon, which could further exacerbate the number of cases that must be
developed to comply with the coordination process under R3.
To address this concern, the SRC recommends a neutral third party identify the scenarios for Interconnections with more than one PC. Extreme
temperature events in such Interconnections will typically extend beyond the footprint of a single Planning Coordinator. To avoid putting the PCs in a
position where they are required to agree on a scenario, a year and the sensitivity to be studied, NERC or some other entity (e.g. Eastern
Interconnection Reliability Assessment Group, ERAG) should identify the extreme heat and extreme cold temperature events to be studied. This is
necessary to ensure consistent modeling results across adjacent planning entities within an Interconnection. Also, as a benchmark temperature event
may extend across several planning areas, the neutral third party must take this into consideration when determining which extreme heat and extreme
cold temperature events are to be studied so that no planning entity is assigned more than one of each.
R4. SRC supports the proposed language (“data consistent with that provided in accordance with the MOD-032 standard”) and does not see a need to
update MOD-032 at this time; however, depending upon what data the benchmark temperature event requires to perform the study, this may need to be
revisited.
R5. SRC supports the addition of “and applicable Facility Ratings” considering the need to comply with FERC Order 881 and Ambient Adjusted
Ratings in the near future. SRC members are also exploring this further with their member TOs.
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Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

No

Document Name
Comment
PGAE agrees with R5 and R6 but does not agree with R4. Extreme Temperature Events are already a “sensitivity” to normal long-term planning cases
and are be built with Gen/Load/Transfer based on the extreme weather conditions of an entity’s territory. Additional, mandatory “sensitivity cases”
seems redundant in nature.
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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT joins the comments submitted by the IRC SRC and adopts them as its own.

In addition, ERCOT is concerned that Requirement R4, Part 4.1 unnecessarily and inadvertently limits the ability of entities to properly develop their
benchmark planning cases. Specifically, ERCOT is concerned that Part 4.1 could be understood to mean that entities are limited to making the
adjustments specifically described in Part 4.1 and are prevented from making adjustments necessary to update the planning cases to reflect the
expected future state of the system or to ensure that the generation necessary to serve load is available so that the case can solve. Adjusting the case
to ensure that it contains enough generation to serve the modeled load is essential to ensure that the standard does not address resource adequacy
issues and fully complies with paragraph 94 of FERC Order No. 896, which states that resource adequacy is not in scope for this project.

ERCOT is also concerned that Part 4.1 could be understood to require entities to model facility derates and outages that were actually observed during
the selected benchmark temperature event rather than requiring entities to model impacts of the temperatures observed during that event on the system
as it is expected to exist in the year being evaluated. To address these concerns, ERCOT recommends that Part 4.1 be revised to read as follows:

4.1 Benchmark planning cases that reflect the expected future state of the System and include seasonal and temperature dependent adjustments
for Load, generation, Transmission, and transfers based on the weather conditions described in the selected benchmark temperature events as
identified in Requirement R2 for one of the years in the Long-Term Transmission Planning Horizon. The responsible entity may adjust the total
modeled generation or Load in each case as necessary to allow the total modeled generation to serve the total modeled System Load. The
rationale for the year selected for evaluation shall be available as supporting information. This establishes Category P0 as the normal System condition
in Table 1.

ERCOT also recommends that Requirement R3 be revised as needed to align with any revisions made to Requirement R4.
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Elizabeth Davis - Elizabeth Davis On Behalf of: Thomas Foster, PJM Interconnection, L.L.C., 2; - Elizabeth Davis
Answer
Document Name

No

Comment
PJM supports the IRC SRC comments.
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Response
Robert Blackney - Edison International - Southern California Edison Company - 1
Answer

No

Document Name
Comment
See comments submitted by Edison Electric Institute
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Response
John Brewer - National Energy Technology Laboratory - 9 - NA - Not Applicable
Answer

No

Document Name
Comment
(R3) It is unclear who the “other designated study entities” are and who defines them.

(R3) R2 Requirement allows each responsible entity to select different benchmark temperature event(s). R3 should be revised to clarify how conflicts will be resolved
if different Planning Coordinators within the same Interconnection select different events.

(R4.1) In Order 896 paragraph 88, FERC directs “NERC to require under the new or revised Reliability Standard the study of concurrent/correlated generator and
transmission outages due to extreme heat and cold events in benchmark events,” explaining in paragraph 89 that “it is necessary that responsible entities evaluate
the risk of correlated or concurrent outages and derates of all types of generation resources and transmission facilities as a result of extreme heat and cold events.”
We suggest modifying “Benchmark planning cases that include seasonal and temperature dependent adjustments for Load, generation, Transmission, and transfers”
to include “concurrent/correlated generator and transmission outages.”

Allowing benchmark planning cases for “one of the years in the Long-Term Transmission Planning Horizon” will burden each responsible entity with developing
necessary adjustments for a different year than the adjacent responsible entity selected if they do not select the same year.

(R4.2) If sensitivity analysis allows the selection of only one condition, R4.2 should be revised to (1) provide a ranking of what conditions should be selected first, or
(2) provide a process that each responsible entity should follow for the sensitivity analysis with the three listed conditions, or (3) requires all conditions to be
changed during the sensitivity analysis.

(R5) No issue.
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Usama Tahir - Seminole Electric Cooperative, Inc. - 3
Answer

No

Document Name
Comment
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Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer

Yes

Document Name
Comment
M4 should state “Each responsible entity, as identified in Requirement R1,…” to remain consistent with other Measures
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Response
Gary Trezza - Long Island Power Authority - 1 - NPCC

Answer

Yes

Document Name
Comment
Comments/ Questions:

Requirement #5 mentions having criteria for acceptable System steady state voltage limits, post-Contingency voltage deviations, and applicable Facility
Ratings.
Is it the intent that entities will also have to have (and document) applicable thermal criteria for completing the Extreme Temperature Assessment? For
example, allowing for the possible use of STE facility ratings post-contingency?

In certain jurisdiction, extreme temperature ratings have been established, but that is not necessarily the case in all jurisdictions. Will facility owners be
required to establish extreme cold or warm temperature ratings for this standard?
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Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
Duke Energy supports proposed language but requires clarification of the phrase “other designated study entities”.
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Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
AZPS generally supports the updates made by the STD to R3 – R5. AZPS also supports the comments that were submitted by EEI on behalf of its
members that R3 does not provide sufficient clarity for the processes or expectations for coordination between adjacent Planning Coordinators and

Transmission Planners, including the deadlines for the review of the Extreme Temperature Assessments by adjacent PCs and TPs. Please see EEI
comments regarding recommended changes to the requirement.
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Apollonia Gonzales - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer

Yes

Document Name
Comment
R3 and R4.4 should include facility ratings since FERC Order 881 establish AAR. Seasonal rating typically used in planning studies would not be
appropriate for the extreme weather assessment.

… include seasonal and temperature dependent adjustment for Load, generation, Transmission, facility ratings, and transformers…

The SDT should consider making the definition of Extreme Temperature Assessment align better with the definition of Planning Assessment.
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Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
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Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

Yes

Document Name
Comment
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Response
Barbara Marion - Dominion - Dominion Resources, Inc. - 5, Group Name Dominion
Answer

Yes

Document Name
Comment
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0

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Robert Follini - Avista - Avista Corporation - 3
Answer

Yes

Document Name
Comment
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0

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Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

Yes

Document Name
Comment
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0
0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
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0

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Teresa Krabe - Lower Colorado River Authority - 5
Answer

Yes

Document Name
Comment
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0

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Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
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Matt Lewis - Lower Colorado River Authority - 1
Answer
Document Name

Yes

Comment
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE has the following recommendations for Requirement R3:
•
•

Provide clarification around “adjacent impacted Planning Coordinators, Transmission Planners, and other designated study entities”. If the
Planning Coordinator (PC) determines an adjacent PC or Transmission Planner (TP) is not impacted, justification should be provided.
The goal for Requirement R3, is for the PC to have a process which describes the methodology used to define temperature dependent
adjustments to the overall load, generation, transmission ratings, and transfers to match the benchmark temperature level compared to the
seasonal ratings in order for consistent temperature dependent adjustments to be utilized by all the impacted entities within the
interconnection. Texas RE recommends the following revision to Requirement R3 (in bold):

R3. Each Planning Coordinator shall develop and implement a process for coordinating the development of benchmark planning cases, using the
selected benchmark temperature events identified in Requirement R2, among adjacent impacted Planning Coordinator(s), Transmission Planner(s), and
other designated study entities, within an Interconnection. This process shall include the methodologies used to generate seasonal and the temperature
dependent adjustments for the data inputs such as Load, generation, Transmission, and transfers to represent the selected benchmark temperature
events.

Texas RE has the following recommendations for Requirement R4:
•

Requirements R3 and R4 are currently written in such a way that if an entity fails to meet one of the standards, it will fail to meet the other
one. Texas RE recommends bifurcating both requirements so R3 focuses on developing a process for coordination the development of
benchmark cases, and R4 focuses on implementing the process in Requirement R3 for coordinating the development of the benchmark
case. The term “implement” rather than the term “use” is consistent with other NERC Reliability Standards. Texas RE recommends the
following verbiage:

R3. Each Planning Coordinator shall develop a process for coordinating the development of benchmark planning cases, using the selected benchmark
temperature events…
R4. Each responsible entity, as identified in Requirement R1, shall implement the coordination process developed in accordance with Requirement
R3…
•

Texas RE is concerned that Requirement R4 states the selected benchmark temperature events should be for one of the years in the LongTerm Transmission Planning Horizon. Given the number of variables, the Transmission System could be significantly different 6-10 years in the
future. Texas RE recommends selecting benchmark events for the Near-Term Planning Horizon as there are more known variables.

•

Requirement 4.1 states the “Benchmark planning cases that include seasonal and temperature dependent adjustments for Load,
generation…” This could create some confusion whether a seasonal base case should be developed first and then make the temperature
dependent adjustments for the data points listed. Texas RE recommends removing the word ‘seasonal’ from this requirement.

4.1. Benchmark planning cases that include temperature dependent adjustments for Load, generation, Transmission, and transfers to represent the
System conditions of the selected benchmark temperature events as identified in Requirement R2 for one of the years in the Long-Term Transmission
Planning Horizon. The rationale for the year selected for evaluation shall be available as supporting information. This establishes Category P0 as the
normal System condition in Table 1

For consistency with other Requirement language, Texas RE recommends the following revision for Requirement R5 (in bold):

R5. Each responsible entity, as identified in Requirement R1, shall define and document the criteria for acceptable System steady state voltage limits,
post-Contingency voltage deviations, and applicable Facility Ratings for evaluating the Extreme Temperature Assessment results.

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4. The DT updated Requirements R6 – R8 based on comments received. Do you agree with the updated proposed TPL-008-1 Reliability
Standard Requirements R6-R8? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural
justification.

Long Island Power Authority
Answer

No

Document Name

(if an attachment is provided by submitter)

Comment
Requirement # 7 states:
“Each responsible entity, as identified in Requirement R1, shall identify the planning events for each category in Table 1 that are
expected to produce more severe System impacts on its portion of the Bulk Electric System. The rationale for those
Contingencies selected for evaluation shall be available as supporting information.”
We observe that the above language is slightly different from TPL-001-5.1 Req # 3.4, which states:
“Those planning events in Table 1 that are expected to produce more severe System impacts on its portion of the BES shall be
identified, and a list of those Contingencies to be evaluated for System performance in Requirement R3, Part 3.1 created. The
rationale for those Contingencies selected for evaluation shall be available as supporting information.”
In summary, we observe that TPL-008-1 Req #7 requires the identification of planning events for each category in Table 1 (i.e., P0,
P1, P2, P4, P7), while TPL-001-5.1 Req #3.4 does not explicitly require the identification of planning events for each category in
Table 1.
We are not certain if this distinction (added burden for TPL-008-1 as compared to TPL-001-5.1) was intended by the SDT, as so we
wanted to point this out.
We would also like the SDT to clarify if the intent is that the entity must identify contingencies for each “Category” (P2 for
example) AND each “Event” (P2.1 for example). Without clarification, this requirement could be interpreted differently by
auditors.
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# of other submitters who agree with these comments
0

# of other submitters who disagree with these comments

Response
(Drafting team’s response to submitter’s comments)

John Brewer - National Energy Technology Laboratory - 9 - NA - Not Applicable
Answer

No

Document Name
Comment
(R6) No issue.
(R7) No issue.
(R8) It is not clear if steady state and transient stability analysis using the identified contingencies from R7 should be included in every 8.1 (the benchmark planning
cases developed in accordance with Requirement R4 Part 4.1.) and 8.2 (the sensitivity cases developed in accordance with Requirement R4 Part 4. 2.) analysis.

The Technical Rationale for R8 Requirements specifies the minimum number of assessments (a minimum of one benchmark planning case analysis for extreme cold,
a minimum of one for extreme heat, a minimum of one sensitivity study case for one condition for extreme cold, and a minimum of one sensitivity study case for one
condition for extreme heat). We suggest clarifying this in 4.1. and 4.2.
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Apollonia Gonzales - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer

No

Document Name
Comment
PNM agrees with EEI's comments and feedback for this question.
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Robert Blackney - Edison International - Southern California Edison Company - 1
Answer
Document Name
Comment

No

See comments submitted by Edison Electric Institute
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0

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Elizabeth Davis - Elizabeth Davis On Behalf of: Thomas Foster, PJM Interconnection, L.L.C., 2; - Elizabeth Davis
Answer

No

Document Name
Comment
PJM supports the IRC SRC comments.
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0

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0

Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT joins the comments submitted by the IRC SRC and adopts them as its own.
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0

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0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
Document Name
Comment

No

PGAE has no comment on R6 or R7, however, we disagree with the proposed R8. See above comments for Question 3 related to R4, as R8 is in
reference to R4.
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Bobbi Welch - Midcontinent ISO, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee (SRC) Project 2023-07 TPL-008-1 Draft #2
Answer

No

Document Name
Comment
The SRC supports some of the revisions and proposes modifications to others as detailed below.
R6 needs better wording to indicate instability, uncontrolled separation and cascading must all be monitored for. The “or” makes it seem like only one of
the three must be addressed.
R7. SRC supports the SDT’s decision to modify the language from “Contingencies” to “planning events;” however, we believe a similar change should
be made to the second reference to “Contingencies” later in the paragraph (see sentence 2). SRC proposes the edit below.
R7. Each responsible entity, as identified in Requirement R1, shall identify the planning events for each category in Table 1 that are expected to
produce more severe System impacts on its portion of the Bulk Electric System. The rationale for those planning events selected for evaluation shall
be available as supporting information.
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0

Response
Usama Tahir - Seminole Electric Cooperative, Inc. - 3
Answer

No

Document Name
Comment
Seminole would like a longer implementation timeline for R7 of 72 months to determine which planning events produce more severe planning events.
Likes

0

Dislikes
Response

0

Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
Please refer to Question 1 comments.
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0

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0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

No

Document Name
Comment
In R7, ITC has concerns with the term planning event and believes that this should be changed to contingencies. To ITC, the term planning event
should be used to describe the benchmark event, not the outage of a portion of the grid.
The DT needs to identify which system this standard is applicable to analyze. ITC believes it should remain the Bulk Electric System (BES) rather than
being applicable to the Bulk Power System (BPS). NERC standards do not typically apply to the BPS. Entities that own the BES system in an area can
identify any concerns for the BES. If an entity does not own the BPS also, applying it to the BPS would expose them to issues outside of their control.
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0

Response
Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer

No

Document Name
Comment
R6 could be moved to the beginning of the R2-R5 section or be included as part of the Operating Plan as described in our response to Question 1.
R7 requires testing of all the events listed in Table 1, however R9 only requires the development of CAPs for the P0 and P1 contingencies.
ISO-NE recommends modifying Table 1 to only include P0 and P1 events in accordance with the FERC Order 896 Paragraph 113 Commission
Determination that “NERC may determine whether contingencies P1 through P7 should also apply to the new or modified Reliability Standard, or

whether a new set of contingencies should be developed.” Paragraph 113 of the Commission Determination does not require the inclusion of events
other than P0. ISO-NE believes P0 and P1 events are acceptable for this Standard, however, P2, P4, and P7 events are not.
The technical Rationale for R10 should be modified to remove “However, due to their potential severity resulting from single Contingency multiple
element outages, the SDT believes it is appropriate for responsible entities to at least evaluate and document possible mitigation actions to reduce the
likelihood or mitigate the consequences and adverse impacts. The biggest benefit from the evaluation and documentation of the mitigating actions is it
allows an entity to see where major problems exist that they may need to be addressed; and, if a project shows up on enough issues, it may encourage
a fix to be implemented without it being strictly called for from the standard. Not requiring CAPs for these contingencies but requiring the evaluation is a
compromise from having CAPs for all studied issues.”
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Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
R6:
•

•
•

The inclusion of “within an Interconnection” is not appropriate as the PC or TP should not be required to assess outside of its applicable area.
Note the inclusion of more appropriate language referring to the PC’s or TP’s planning area (its portion of the Bulk Electric System) in this draft
so it is not clear why some requirements refer to an Interconnection while others, more correctly, refer to the area of actual responsibility for the
PC or TP.
The following bullet contains a wording addition to clarify the applicability of this requirement to System-wide impacts. This is also consistent
with wording in other Reliability Standards when referencing these types of impacts.
“Each responsible entity, as identified in Requirement R1, shall define and document the criteria or methodology used in the Extreme
Temperature Assessment analysis to identify instability, uncontrolled separation, or Cascading of the Bulk Electric System.”

R7 & R8:
•

•

•
•

It does not appear likely that P0 & P1 events would be “expected to produce more severe System impacts” in typical planning
studies. However, with an extreme weather scenario as the baseline, a P0 or P1 may produce more severe impacts due to the anomalous
starting point. It would make more sense to allow the PC/TP to develop the appropriate study methodology (and document it) to appropriately
analyze the required benchmark. Focusing on traditional P-event definitions and recycling language from TPL-001 is not appropriate since the
analysis/assessments between the two standards is drastically different.
The standard does not clearly and specifically state whether steady-state and/or stability analysis is to be performed for the identified events as
TPL-001 does for instance. The SDT should consider modifying R7 to allow the responsible entity to develop a methodology or rationale in the
performance of a benchmark event to appropriately assess it for that entity’s planning area, otherwise, additional clarity in the analysis
expectations is needed. Different weather events would require a different consideration of applicable contingencies and analysis approaches.
Adding “transient” to qualify stability may result in more confusion in interpretation between planning entities, auditors, and the referenced
ERO. There is a requirement to document stability criteria so this should be clear based on that documentation. Adding “transient” therefore is
more detrimental than helpful to this standard.
Some of the lack of clarity may be related to the lack of clarity around the composition of the benchmark events to be determined. If these
benchmark events are limited to temperature profiles versus temperature profiles and potential resultant generation unavailability (for example),
the responsible entity’s analysis approach will potentially vary.

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Response
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer

No

Document Name
Comment
SPP has concerns in reference to Requirement R7 and the applicability of Table 1 creating issues for industry by applying the extreme weather event
matrix to this standard as it creates issues with the base case and scenario results.
At this point, it is unclear how the base case will translate the benchmarked events into the models. Moreover, it is unclear on the expectations of
handling the events in the Table 1. For example, our initial assessment would lead us to believe that we will need to evaluate a P1 event like a P6
event.
Finally, there is a concern about the validity of the issues that maybe found dearing in this assessment and resulting dollars for CAPs.
SPP recommends that the drafting team provide clarity around their expectations for Table 1 by using the current events information from TPL-001 or
revisioning those events to align appropriate with the requirements of the assessment for the TPL-008.
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0

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0

Response
Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer

No

Document Name
Comment
The phrase “within an Interconnection” may need to be clarified or defined.
Likes

0

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0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

No

Document Name
Comment
Tri-State supports the comments submitted by the MRO NSRF.
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0

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0

Response
Greg Sorenson - Greg Sorenson On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Greg Sorenson
Answer

No

Document Name
Comment
Similar to the CIP-014 project, R6 includes “instability, uncontrolled separation, or Cascading". This is similar to, yet slightly different from, the defined
term Interconnection Reliability Operating Limit (IROLs).
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0

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0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

No

Document Name
Comment
Minnesota Power supports MRO’s NERC Standards Review Forum’s (NSRF) comments.
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0

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0

Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Document Name
Comment

No

Requirement R7 struck “Contingencies” and replaced that with “the planning events” in the first sentence but did not strike “Contingencies” in the
second sentence. It is not clear as to why the change was made as “Contingency” is defined while “planning event” is not. Requirement R8 uses the
phrase “Contingencies identified in Requirement 7” which is not supported by the proposed language of Requirement R7. The Technical Rational
supports and reiterates the use of Contingency. FERC Order 896 stated (and is listed in the Technical Rationale): “[w]e believe that it is necessary to
establish a set of common contingencies for all responsible entities to analyze. Required contingencies, such as those listed in Table 1 of Reliability
Standard TPL-001-5.1 (i.e., category P1 through P7), establish common planning events that set the starting point for transmission system planning
assessments,”.
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0

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0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

No

Document Name
Comment
Please see comments from EEI
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0

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0

Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment
EEI does not have concerns with Requirement R6 or Requirement R8, however, we do suggest some non-substantive changes to Requirement
R7. Specifically, we suggest changing “planning event” to “contingency event” to align with Table 1.1 more clearly. Our suggested changes are
indicated below in boldface.

R7. Each responsible entity, as identified in Requirement R1, shall identify the contingency events for each category in Table 1.1 that are expected
to produce more severe System impacts on its portion of the Bulk Electric System. The rationale for those Contingencies selected for evaluation shall
be available as supporting information. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
Likes
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0
0

Response
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer

No

Document Name
Comment
In R7, Ameren recommends changing "Contingencies" to "planning events" in the last sentence. This would align with the revision made in the first part
of R7. In addition, Ameren agrees with and supports EEI's comments.
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0

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0

Response
Israel Perez - Israel Perez On Behalf of: Laura Somak, Salt River Project, 3, 6, 5, 1; Mathew Weber, Salt River Project, 3, 6, 5, 1; Thomas
Johnson, Salt River Project, 3, 6, 5, 1; Timothy Singh, Salt River Project, 3, 6, 5, 1; - Israel Perez
Answer

No

Document Name
Comment
Define Table 1 for requirement R7. We also request increased clarity on the case selection & building process required in R4.
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0

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0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

No

Document Name
Comment
The Requirement R7 language is not clear whether the responsible entity should evaluate the impact of each of the Contingencies listed in Table 1.1 or
the responsible entity is to guess (or select based on some rationale criteria) which contingency event will produce more severe System impacts on its
portion of the BPS. Additionally, while the requirement language states there should be rationale for those Contingencies selected, there is no language
saying there should be rationale for the Contingencies not selected. Texas RE recommends language to require rationale for both why certain
Contingencies are selected and why others are not selected.
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0

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0

Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment
Southern Company requests that the phrase “within an Interconnection” be clarified or defined. Southern Company would like clarification on why
transient stability is specified in R8, but not other portions of the standard.
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0

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0

Response
Richard Vendetti - NextEra Energy - 5
Answer

No

Document Name
Comment
NextEra supports EEI's comments
EEI does not have concerns with Requirement R6 or Requirement R8, however, we do suggest some non-substantive changes to Requirement
R7. Specifically, we suggest changing “planning event” to “contingency event” to align with Table 1.1 more clearly. Our suggested changes are
indicated below in boldface.

R7. Each responsible entity, as identified in Requirement R1, shall identify the contingency events for each category in Table 1.1 that are expected
to produce more severe System impacts on its portion of the Bulk Electric System. The rationale for those Contingencies selected for evaluation shall
be available as supporting information. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
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0

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0

Response
Kevin Conway - Western Power Pool - 4
Answer
Document Name

No

Comment
R6 and R7 Risk factors should be Medium to match TPL 001-5.
Likes

0

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0

Response
Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

No

Document Name
Comment
For R6 & R7, Santee Cooper suggests the VRF’s be Medium to match TPL-001-5. We also feel like the additional sensitivity studies required in R8.2
would add a significant administrative burden without more clarification to how it benefits the long term planning horizon.
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0

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0

Response
Amy Wilke - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
ATC supports the MRO NSRF comments.
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0

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0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Document Name
Comment

No

Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and the Midwest Reliability Organization's NERC
Standards Review Forum (MRO NSRF) on question 4
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0

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Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

No

Document Name
Comment
The Violation Risk Factor (VRF) for Requirements R7 and R8 are designated as High, however, the VRF for similar requirements in TPL-001-5 are
designated as Medium. The VRF for Requirements R7 and R8 in TPL-008-1 should be set to Medium to match TPL-001-5.
Likes

0

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0

Response
Robert Jones - Seattle City Light - 1,3,4,5,6
Answer

No

Document Name
Comment
R6 and R7 Risk factors should be Medium to match TPL-001-5.
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0

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0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer
Document Name

No

Comment
For R6, Oncor urges its comment from R5. The PC would need to ensure that all entities use the same methodology and criteria for instability,
uncontrolled separation, or Cascading.
For R8, Oncor asks whether language can be added to ensure that entities can take credit for studies that are run as part of the Extreme Temperature
Assessment, rather than running those studies again as part of the assessment to be conducted under TPL-001? For example, the Extreme
Temperature Assessment could take the place of the sensitivity analysis required within the TPL-001 assessment for both the steady state and stability
analyses.
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0

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0

Response
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

No

Document Name
Comment
MRO NSRF supports some of the revisions and proposes modifications to others as detailed below.
R6 needs better wording to indicate instability, uncontrolled separation and cascading must all be monitored for. The “or” makes it seem optional.
R7. MRO NSRF supports the SDT’s decision to modify the language from “Contingencies” to “planning events;” however, we believe a similar change
should be made to the second reference to “Contingencies” later in the paragraph (see sentence 2). MRO NSRF proposes the edit below.
R7. Each responsible entity, as identified in Requirement R1, shall identify the planning events for each category in Table 1 that are expected to
produce more severe System impacts on its portion of the Bulk Electric System. The rationale for those Contingencies planning events selected for
evaluation shall be available as supporting information.
Part 8.1 MRO NSRF supports Part 8.1 and the analysis of the benchmark planning cases developed pursuant to Requirement 4, Part 4.1. As noted
above, MRO NSRF views the benchmark temperature event as a “base case sensitivity” to that performed under TPL-001 and asks whether all
sensitivities can be “baked into” the benchmark temperature event.
Likes

1

Dislikes

Scott Brame, N/A, Brame Scott
0

Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Document Name
Comment

No

Dominion Energy supports EEI comments. In addition, Dominion Energy is concerned over the ambiguity in the CAP process and would appreciate
additional clarity on the role of the ERO in the CAP process.
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0

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0

Response
Zahid Qayyum - New York Power Authority - 5
Answer

No

Document Name
Comment
The Violation Risk Factor for R6 and R7 is currently ‘high’ and should be lowered to ‘medium’ to align with TPL 001-5.1
Likes

0

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0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

No

Document Name
Comment
FirstEnergy supports EEI’s comments which state:
EEI does not have concerns with Requirement R6 or Requirement R8, however, we do suggest some non-substantive changes to Requirement
R7. Specifically, we suggest changing “planning event” to “contingency event” to more clearly align with Table 1.1. We also note that Bulk Power
System was incorrectly identified as Bulk Electric System. Our suggested changes are indicated below in boldface:
R7. Each responsible entity, as identified in Requirement R1, shall identify the contingency events for each category in Table 1.1 that are expected
to produce more severe System impacts on its portion of the Bulk Electric Power System. The rationale for those Contingencies selected for evaluation
shall be available as supporting information. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
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0

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0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF

Answer

No

Document Name
Comment
Duke Energy agrees with and recommends implementation of EEI comments.
Likes

0

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0

Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

No

Document Name
Comment
The standard practice is to first identify the base-case planning scenarios to perform the extreme temperature assessment and then identify the
applicable contingencies. The revised wording in R7 is confusing and does not convey the correct message. Please refer to the specific table when
referring to contingencies and performance requirements, for example, refer to Table 1.1 the contingencies to be studies and Table 1.2 for the
performance requirements. It is expected that the SDT will revise R7 to make this clarification.
Manitoba Hydro does not think there is a need to perform additional sensitivity studies as per R 8.2 (see our response to R 4.2 under comment -3).
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0

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0

Response
Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

No

Document Name
Comment
Requirement # 7 states:
“Each responsible entity, as identified in Requirement R1, shall identify the planning events for each category in Table 1 that are expected to produce
more severe System impacts on its portion of the Bulk Electric System. The rationale for those Contingencies selected for evaluation shall be available
as supporting information.”
We observe that the above language is slightly different from TPL-001-5.1 Req # 3.4, which states:

“Those planning events in Table 1 that are expected to produce more severe System impacts on its portion of the BES shall be identified, and a list of
those Contingencies to be evaluated for System performance in Requirement R3, Part 3.1 created. The rationale for those Contingencies selected for
evaluation shall be available as supporting information.”

In summary, we observe that TPL-008-1 Req #7 requires the identification of planning events for each category in Table 1 (i.e., P0, P1, P2, P4, P7),
while TPL-001-5.1 Req #3.4 does not explicitly require the identification of planning events for each category in Table 1.
We are not certain if this distinction (added burden for TPL-008-1 as compared to TPL-001-5.1) was intended by the SDT, as so we wanted to point this
out.
We would also like the SDT to clarify if the intent is that the entity must identify contingencies for each “Category” (P2 for example) AND each “Event”
(P2.1 for example). Without clarification, this requirement could be interpreted differently by auditors.
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0

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0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

No

Document Name
Comment
CHPD believes the updates made to R6 through R8 were very good, with one concern for R6 and R7 remaining. The VRF for the ‘Bad 3’ criteria and
contingencies/rational are both set as ‘High’ as proposed in TPL-008, while the same type of limits requirement has a VRF of ‘Medium’ in TPL-001-5 R6
and R3.4/R4.4 respectively. It is requested the VRF for TPL-008 R6 and R7 be similarly set as ‘Medium’ for consistency.

Likes

1

Dislikes

Jennie Wike, N/A, Wike Jennie
0

Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Document Name
Comment
(R6) No issues.
(R7) No issues.

No

(R8.2) We do not agree that R8.2, which requires an increasingly more extreme scenario for purposes of a sensitivity analysis, is credible. This is
especially true for longer term planning horizons when generation additions and retirements, along with transmission configuration changes and new
technologies to be deployed are less detailed.
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0

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0

Response
Chelsea Loomis - Western Power Pool - NA - Not Applicable - WECC, Group Name WPP Consortium of Engineers
Answer

No

Document Name
Comment
R6 and R7 Risk factors should be Medium to match TPL 001-5.
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0

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0

Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer

No

Document Name
Comment
If R8 refers to Contingencies identified in requirement R7, why was the use of “contingencies” in R7 changed to “planning events”. Recommend
changing R7 back to contingencies for consistency. When referring to contingencies in table 1, suggest updating to table “1.1”.
Likes

0

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0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer
Document Name
Comment

No

R6, and R7 VRFs are 'high', but they should be Medium to match TPL 001-5.
Likes

2

Dislikes

Snohomish County PUD No. 1, 3, Chaney Holly; Jennie Wike, N/A, Wike Jennie
0

Response
Ben Hammer - Western Area Power Administration - 1
Answer

Yes

Document Name
Comment
R6. Each responsible entity, as identified in Requirement R1, shall define and document the criteria or methodology used in the Extreme Temperature
Assessment analysis to identify instability, uncontrolled separation, and Cascading. within an Interconnection.
Likes

0

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0

Response
Kinte Whitehead - Exelon - 3
Answer

Yes

Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
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0

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0

Response
Helen Lainis - Independent Electricity System Operator - 2
Answer
Document Name
Comment

Yes

We support the SDT’s decision to modify the language from “Contingencies” to “planning events;” however, we believe a similar change
should be made throughout the proposed standard.
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0

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0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

Yes

Document Name
Comment
Black Hills Corporation has no concerns with the updated language for requirements R6, R7, and R8.
Likes

0

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0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
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0

Dislikes

0

Response
Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.

Likes

0

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0

Response
Ronald Hoover - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
BPA recommends R6 and R7 Risk factors should be set to Medium to match TPL 001-5.
For R7, BPA recommends adding “and create a list of Contingencies to be evaluated”.
Each responsible entity, as identified in Requirement R1, shall identify the planning events for each category in Table 1 that are expected to produce
more severe System impacts on its portion of the Bulk Electric System and create a list of Contingencies to be evaluated. The rationale for those
Contingencies selected for evaluation shall be available as supporting information.
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0

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0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Matt Lewis - Lower Colorado River Authority - 1
Answer

Yes

Document Name
Comment
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0

Dislikes

0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Teresa Krabe - Lower Colorado River Authority - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Michele Tondalo - United Illuminating Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Junji Yamaguchi - Hydro-Quebec (HQ) - 5
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

Response
Robert Follini - Avista - Avista Corporation - 3
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Barbara Marion - Dominion - Dominion Resources, Inc. - 5, Group Name Dominion
Answer

Yes

Document Name
Comment
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0

Dislikes

0

Response
Donald Lock - Talen Generation, LLC - 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 NPCC RSC
Answer
Document Name

Yes

Comment
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0

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0

Response
Fon Hiew - NB Power Corporation - New Brunswick Power Transmission Corporation - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Jessica Cordero - Unisource - Tucson Electric Power Co. - 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
Jeffrey Streifling - NB Power Corporation - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza
Answer
Document Name
Comment

Yes

Likes

0

Dislikes
Response

0

5. The DT updated Requirement R9 based on comments received. Do you agree with the updated proposed TPL-008-1 Reliability Standard
Requirement R9? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural justification.
Long Island Power Authority

Answer

No

Document Name

(if an attachment is provided by submitter)

Comment
Requirement #9.3 states:
“Be permitted to utilize Non-Consequential Load Loss as an interim solution, which normally is not permitted in Table 1, in
situations that are beyond the control of the Planning Coordinator or Transmission Planner that prevent the implementation of a
Corrective Action Plan in the required timeframe.”
The Extreme Temperature Assessment would have to be performed at least once every 5 years, assessing one year in the Long
Term Planning Horizon.
It is recognized that the details of the extreme heat/cold benchmark temperature events may change over time, and that the
underlying assumptions utilized in the Extreme Temperature Assessment for one of the years in the Long Term Planning Horizon
may change over time. CAPs identified in one Assessment may not be needed in a future Assessment. It may be difficult to pursue
expensive CAPs understanding that assumptions may change.
With this in mind, we find it difficult from a compliance perspective to clearly identify what is meant by “in the required
timeframe”. This language, while allowing for flexibility, seems very ambiguous. The Technical Rationale does not elaborate on
this point.
We recommend that the SDT clarify what is intended by “in the required timeframe.”
Likes

0

Dislikes

# of other submitters who agree with these comments
0

# of other submitters who disagree with these comments

Response
(Drafting team’s response to submitter’s comments)
Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza
Answer
Document Name

No

Comment
There are already existing processes for interactions with applicable regulatory authorities and governing bodies regarding CAP for many other issues
and items. Extreme weather CAPs are not exceptions and do not need a new way to solicit feedback. R9.1 should be removed because it also creates
a compliance requirement without any benefit to reliability and would be confusing.
Likes

0

Dislikes

0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer

No

Document Name
Comment
There are already existing processes for interactions with applicable regulatory authorities and governing bodies regarding CAP for many other issues
and items. Extreme weather CAPs are not exceptions and do not need a new way to solicit feedback. R9.1 should be removed because it also creates
a compliance requirement without any benefit to reliability and would be confusing.
Likes

0

Dislikes

0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

No

Document Name
Comment
The "applicable regulatory authorities... electric service" needs better clarification - what does this look like for Jurisdisctionals vs non-Jurisdictionals - is
this not applicable to non-Jurisdictionals? Ask of SDT to provide better guidance & examples. Could NERC provide some examples for both
jurisdictional entities and non-jurisdictional entities for what is intended for this standard. It is highly recommended using operation procedures instead
of CAPs since operation procedures have more flexibility to respond to a system’s needs and adapt proactively.
Likes

2

Dislikes

Snohomish County PUD No. 1, 3, Chaney Holly; Jennie Wike, N/A, Wike Jennie
0

Response
Chelsea Loomis - Western Power Pool - NA - Not Applicable - WECC, Group Name WPP Consortium of Engineers

Answer

No

Document Name
Comment
Language unclear pertaining to non-jurisdictionals, could NERC provide some examples for both jurisdictionals and non-jurisdictionals for what is
intended for this standard? applicable regulatory authorities or governing bodies responsible for retail electric service" needs better clarification - what
does this look like for Jurisdisctionals vs non-Jurisdictionals - is this not applicable to non-Jurisdictionals? Ask of SDT to provide better guidance and
examples here.

Could operational procedures be used in lieu of a CAP as an acceptable mitigation?

Likes

0

Dislikes

0

Response
Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
R9.3 The phrase "required timeframe" is unclear and should be more thoroughly defined.
Likes

0

Dislikes

0

Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
(R9.1) We cannot agree with R9.1 without further clarification of how “applicable” entities are determined. We recommend that the reference to
“applicable” entities in R9.1 should be integrated into R3, suggesting that “applicable” entities shall be identified as part of R3 coordination process
developed by the PC.

(R9.2) We cannot agree with R9.2 due to the lack of understanding of the value for “alternative considerations”. The analysis process to determine how
best to meet performance requirements is quite complex and comprehensive. We believe attempting to document, notify, and discuss alternatives that
were deemed less reliable, less economical, and therefore less impactful to ensure system performance would be an inefficient and ineffective task, and
likely to cause more confusion that clarity.
(R9.3) No issues.
(R9.4) No issues.
Likes

0

Dislikes

0

Response
Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer

No

Document Name
Comment
Comments:
We think R9.1 should be removed because it creates a compliance requirement without any incremental benefit to reliability. It further conflicts with
existing planning requirements and processes.

Please see comment on R10.
Likes

0

Dislikes

0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

No

Document Name
Comment
CHPD believes the updates made to R9 were very good, with a couple concerns remaining. The first concern is to the statement ‘make their CAP
available’ in R9.1. CHPD suggests this be changed to ‘make available on request’, to align with a similar request-based mechanism under R11. We’ve
found the general ‘make available’ is murky language for compliance.
The second concern is the expectation in 9.1 and 9.2 for soliciting feedback and notifications to ‘regulatory authorities or governing bodies responsible
for retail electric service issues. The intent here is not clear. Could the SDT provide some examples of what is intended here, both for Jurisdictional and

non-Jurisdictional entities? Furthermore, it is noted that the Measures for R9 do not appear to include the solicitation and notification as part of the
measures for compliance with R9.
Likes

1

Dislikes

Jennie Wike, N/A, Wike Jennie
0

Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

No

Document Name
Comment
R9 and Table 1 requires the development of Corrective Action Plans for P1 events where applicable facility ratings are exceeded and steady state
voltages are not within limits. This requirement goes beyond the directives in FERC Order 896. The FERC Order is concerned with cascading,
instability, and uncontrolled islanding but not with facility overloads.
Likes

0

Dislikes

0

Response
Ronald Hoover - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA views this as an extreme event that doesn’t occur often. BPA recommends these issues be resolved in the operational time horizon through
operating plans. BPA believes an operating plan would provide acceptable performance for an extreme event. BPA believes an operating plan could be
used in lieu of a Corrective Action Plan.
Likes

0

Dislikes

0

Response
Fon Hiew - NB Power Corporation - New Brunswick Power Transmission Corporation - 5
Answer
Document Name
Comment

No

There are already existing processes for interactions with applicable regulatory authorities and governing bodies regarding CAP for many other issues
and items. Extreme weather CAPs are not exceptions and do not need a new way to solicit feedback. R9.1 should be removed because it also creates
a compliance requirement without any benefit to reliability and would be confusing.
Likes

0

Dislikes

0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

No

Document Name
Comment
Duke Energy agrees with and recommends implementation of EEI comments.
Additionally: (a) Define authorities and governing bodies listed in proposed Requirement 9.1.: “Make their CAP available and solicit feedback from
applicable regulatory authorities or governing bodies responsible for retail electric service issues” and
(b) Modify R9.2. to read ‘Document “any” alternative(s) considered’, since scenarios may only have one option and prove unrealistic for all scenarios.
Likes

0

Dislikes

0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

No

Document Name
Comment
FirstEnergy requests the DT to clarify intent providing feedback toward CAP – timeframe of soliciting feedback and what actions would result from
providing feedback. Clarify who applicable “regulatory authorities or governing bodies for retail service” would be.
FirstEnergy also supports EEI’s comments which state:
EEI offers non-substantive edits in boldface below to Requirement R9.
R9.
Each responsible entity, as identified in Requirement R1, shall develop a Corrective Action Plan(s) (CAPs) when the assessment of a
benchmark planning case, in accordance with Requirement R8 Part 8.1, indicates its portion of the Bulk Electric Power System is unable to meet
performance requirements for Table 1.1 P0 or P1 Contingencies. For each Corrective Action Plan, the responsible entity shall: [Violation Risk Factor:
High] [Time Horizon: Long-term Planning]

Likes

0

Dislikes

0

Response
Zahid Qayyum - New York Power Authority - 5
Answer

No

Document Name
Comment
Regarding R9.1 NYPA request standard drafting team to clarify the term "applicable regulatory authorities...electric service" for better clarification and
understanding.
Likes

0

Dislikes

0

Response
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

No

Document Name
Comment
The MRO NSRF recommends the SDT adopt one of the two options (below) and clarify the requirements for each.:
Option #1:
•
•

R9 should focus solely on either benchmark cases for power flow and stability and
R10 should focus solely on sensitivity cases for each

Option #2:
•
•

R9 should focus on power flow for both benchmark and stability and
R10 focus on sensitivity study requirements for both power flow and dynamic stability.

MRO NSRF observes that R9 addresses Load Loss under TPL-008 whereas this is addressed under TPL-001 in TPL-001-5.1, Table 1. The first
sentence of Part 9.3 should be stricken from the standard as illustrated below because it is explanatory in nature and adds no value to the standard.
MRO NSRF recommends this be migrated to the Technical Rationale if the SDT feels it is important to retain.

9.3.The use of Non-Consequential Load Loss as an interim solution in this situation is permitted, provided that each responsible entity documents the
situation causing the problem, alternatives evaluated, and takes actions to resolve the situation.

(Please review the attached document, question 1).
Likes

1

Dislikes

Scott Brame, N/A, Brame Scott
0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer

No

Document Name
Comment
There are already existing processes for interactions with applicable regulatory authorities and governing bodies regarding CAP for many other issues
and items. Extreme weather CAPs are not exceptions and do not need a new way to solicit feedback. R9.1 should be removed because it also creates
a compliance requirement without any benefit to reliability and would be confusing.
Likes

0

Dislikes

0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

No

Document Name
Comment
Oncor strongly disagrees with the following statement in R9.1: “Make their CAP available and solicit feedback from, applicable regulatory authorities or
governing bodies responsible for retail electric service issues.” We propose that “applicable regulatory authorities or governing bodies” be defined and
limited. For example, a TP should only need to provide their PC with CAP information.
In addition, we disagree with the following phrase “and notify the applicable regulatory authorities or governing bodies responsible for retail electric
service issues” as it relates to Load Shed. The intended regulatory audience needs to be clearly defined.
Likes

0

Dislikes

0

Response
Robert Jones - Seattle City Light - 1,3,4,5,6
Answer
Document Name

No

Comment
The language unclear pertaining to non-jurisdictionals. "Applicable regulatory authorities or governing bodies responsible for retail electric service"
needs better clarification - what does this look like for Jurisdisctionals vs non-Jurisdictionals. Is this not applicable to non-Jurisdictionals? Please
provide better guidance and examples here.
Could operational procedures be used in lieu of a CAP as an acceptable mitigation?
Likes

0

Dislikes

0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

No

Document Name
Comment
SMUD supports the comments submitted by the MRO NSRF.
Likes

0

Dislikes

0

Response
Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
The term, “Non-Consequential Load Loss,” is an oxymoron.
Likes

0

Dislikes

0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples

Answer

No

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and the Midwest Reliability Organization's NERC
Standards Review Forum (MRO NSRF) on question 5
Likes

0

Dislikes

0

Response
Amy Wilke - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
ATC supports the MRO NSRF comments.
Likes

0

Dislikes

0

Response
Robert Follini - Avista - Avista Corporation - 3
Answer

No

Document Name
Comment
Avista offers the following suggested comments for consideration:
Avista suggests clarifying that operational procedures may be acceptable mitigation.
Avista suggests NERC does not need to require interactions with regulatory authorities and governing bodies.
Likes

0

Dislikes
Response

0

Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

No

Document Name
Comment
Santee Cooper supports other entity comments for defining regulatory authorities and governing bodies proposed in R9.1. We also suggest modifying
R9.2. to read ‘Document “any” alternative(s) considered’, since scenarios may only have one option and prove unrealistic for all scenarios.
Likes

0

Dislikes

0

Response
Kevin Conway - Western Power Pool - 4
Answer

No

Document Name
Comment
Language unclear pertaining to non-jurisdictionals, could NERC provide some examples for both jurisdictionals and non-jurisdictionals for what is
intended for this standard? applicable regulatory authorities or governing bodies responsible for retail electric service" needs better clarification - what
does this look like for Jurisdisctionals vs non-Jurisdictionals - is this not applicable to non-Jurisdictionals? Ask of SDT to provide better guidance and
examples here. Could operational procedures be used in lieu of a CAP as an acceptable mitigation?
Likes

0

Dislikes

0

Response
Junji Yamaguchi - Hydro-Quebec (HQ) - 5
Answer

No

Document Name
Comment
There are already existing processes for interactions with applicable regulatory authorities and governing bodies regarding CAP for many other issues
and items. Extreme weather CAPs are not exceptions and do not need a new way to solicit feedback. R9.1 should be removed because it also creates
a compliance requirement without any benefit to reliability and would be confusing.
Likes

0

Dislikes
Response

0

Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment
It is Southern Company’s recommendation that the language requiring entities to solicit feedback from regulatory authorities and governing bodies, in
R9.1, should be removed from the standard.
The action of soliciting regulatory feedback/approval does not comport with a risk-based action and only serves as an administrative burden that could
delay reliability improvements to the BES. It is beyond the purview of a reliability standard to mandate a regulatory strategy for the implementation of
projects. The precedent set by TPL-001-5 pertaining to notifying regulatory authorities and governing bodies is specific to the review of nonconsequential load loss and does not support mandating regulatory authority and governing body feedback solicitation as outlined in R9.1.
Further clarification of the recipients and intention for making CAP details available is also required for R9.1 since not all entities fall under the
jurisdiction of a Public Service Commission and considerations need to be made for the sharing of CEII information.
Southern appreciates the inclusion of R9.3 and R9.4 as clarification for CAP development.
Likes

0

Dislikes

0

Response
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer

No

Document Name
Comment
The DT replaced “assessment” with “analysis” in Requirement R8 Part 8.1. It is suggested that the same replacement be made in Requirement R9 for
consistency.
Soliciting feedback from applicable regulatory authorities or governing bodies responsible for retail electric service should not be required for CAPs that
do not include Non-Consequential Load Loss. There is no need to add the administrative burden or introduce the opportunity for disagreements and
delays when the responsible entity is doing something straightforward like reconductoring a transmission line.
This type of solicitation is only required in TPL-001 when Non-Consequential Load Loss is being used as an emergency mitigation option, which is
appropriate. The DT has done the reverse. Normal CAPs require feedback per Parts 9.1 and 9.2. However, the use of Non-Consequential Load Loss as
an emergency mitigation option does not require feedback per Part 9.3. It is recommended that the DT remove Part 9.1 and add the feedback
solicitation to Part 9.3. In this way, any use of Non-Consequential Load Loss (whether planned or emergency alternative) will receive feedback. CAPs
including only standard System upgrades can proceed without the additional coordination.
Likes
Dislikes

0
0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

No

Document Name
Comment
Suggest clarifying that operational procedures may be acceptable mitigation.
Suggest NERC does not need to require interactions with regulatory authorities and governing bodies.
Likes

0

Dislikes

0

Response
Israel Perez - Israel Perez On Behalf of: Laura Somak, Salt River Project, 3, 6, 5, 1; Mathew Weber, Salt River Project, 3, 6, 5, 1; Thomas
Johnson, Salt River Project, 3, 6, 5, 1; Timothy Singh, Salt River Project, 3, 6, 5, 1; - Israel Perez
Answer

No

Document Name
Comment
Define Table 1 for requirement R9. Define who are the regulatory authorities or governing bodies.
Likes

0

Dislikes

0

Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer

No

Document Name
Comment
Requirement R9 should say “Extreme Temperature Assessment” Or “analysis” versus simply “assessment”. It is not clear where and when prevention of
a Corrective Action Plan implementation would occur. Broadly allowing the use of Non-Consequential Load Loss could be detrimental to
reliability. Calling it an “interim solution” with no CAP deadlines set and allowances for “revisions to the CAP in subsequent Extreme Temperature
Assessments” (“subsequent” equals once every five (5) calendar years as a minimum based on a simple compliance approach) essentially creates an
environment where Non-Consequential Load is a compliant result that does not appear to support reliability. Requirement R9 Part 9.4 is unclear. Who

is allowing this to occur? Sounds more like a statement but unsure of who the statement should be for as there is no process for the “permitted” use on
Non-Consequential Load Loss.
Likes

0

Dislikes

0

Response
Teresa Krabe - Lower Colorado River Authority - 5
Answer

No

Document Name
Comment
LCRA agrees with other comments that we strongly disagrees with the following statement in R9.1: “Make their CAP available and solicit feedback from,
applicable regulatory authorities or governing bodies responsible for retail electric service issues.” We propose that “applicable regulatory authorities or
governing bodies” be defined and limited.
Likes

0

Dislikes

0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

No

Document Name
Comment
Minnesota Power supports MRO’s NERC Standards Review Forum’s (NSRF) comments.
Likes

0

Dislikes

0

Response
Matt Lewis - Lower Colorado River Authority - 1
Answer
Document Name
Comment

No

LCRA TSC agrees with other comments that we strongly disagrees with the following statement in R9.1: “Make their CAP available and solicit feedback
from, applicable regulatory authorities or governing bodies responsible for retail electric service issues.” We propose that “applicable regulatory
authorities or governing bodies” be defined and limited.
Likes

0

Dislikes

0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

No

Document Name
Comment
Tri-State supports the comments submitted by the MRO NSRF.
Likes

0

Dislikes

0

Response
Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer

No

Document Name
Comment
The language requiring entities to solicit feedback from regulatory authorities and governing bodies, in R9.1, should be clarified.
Likes

0

Dislikes

0

Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
•

As it stands, “Performance Requirements” referred to in this draft is not clearly defined. Refer to the comment for R5.

•
•
•
•
•
•
•
•

Note the inclusion of language referring to the PC’s or TP’s planning area (its portion of the Bulk Electric System) in this draft so it is not clear
why some requirements refer to an Interconnection while others, more correctly, refer to the area of actual responsibility for the PC or TP.
Refer to previous comments for question 4 regarding referencing specific P events instead of a methodology developed by the PC/TP to
appropriately assess the studied benchmark event.
R9.4 refers to “performance requirements of Table 1”. There are no performance requirements (stable system, loading within Facility
Ratings…) in this draft of Table 1.
The purpose and required response actions related to the sharing of CAPs and solicitation of feedback is not clear.
Documentation of alternatives is an additional administrative burden and provides little benefit to reliability. It is also unclear if there is some
type of expectation these alternatives are reviewed or potentially challenged as invalid.
R9.3 would be better captured in Table 1 similar to TPL-001 Table 1.
The role of the TO and/or GO in implementing or otherwise responding to CAPs that may require additions or modifications to their
systems/facilities is not captured in these requirements.
There appears to be a significant amount of outside review required but no clear actions the responsible entity is required to take, particularly if
there is a dispute. What is the purpose of the review and the expected response? This potentially produces an undue burden on the PC/TP
and adds subjectivity in requiring a review with no documented guidelines for conducting the review.

Likes

0

Dislikes

0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

No

Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments:
There are already existing processes for interactions with applicable regulatory authorities and governing bodies regarding CAP for many other issues
and items. Extreme weather CAPs are not exceptions and do not need a new way to solicit feedback. R9.1 should be removed because it also creates
a compliance requirement without any benefit to reliability and would be confusing.
Likes

0

Dislikes

0

Response
Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer
Document Name
Comment
See SRC Comments

No

Likes

0

Dislikes

0

Response
Ben Hammer - Western Area Power Administration - 1
Answer

No

Document Name
Comment
9.3. The use of Non-Consequential Load Loss as an interim solution in this situation is permitted, provided that each responsible entity documents the
situation causing the problem, alternatives evaluated, and takes actions to resolve the situation.
Likes

0

Dislikes

0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

No

Document Name
Comment
•
•
•

R9.2 ITC believes the requirement for the notification to an applicable regulatory entity should also include a threshold. As written, an entity
would need to make a notification if a proposal tripped 0.1 MW of non-consequential load. Recommend the DT add a threshold in a similar way
as is included in TPL-001 Attachment 1.
R9.3 Delete the first sentence of this sub-requirement. It is explanatory and does not add anything to the intent of R9.
ITC also has a recommended change to Table 1 which therefore would require a change to R9 at a minimum.

Likes

0

Dislikes

0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer
Document Name
Comment
Please refer to Question 1 comments.

No

Likes

0

Dislikes

0

Response
Usama Tahir - Seminole Electric Cooperative, Inc. - 3
Answer

No

Document Name
Comment
NERC, under R9.1, should not add in requirements for other regulatory authorities or governing bodies. Those entities may have approval requirements
that are not clearly laid out here which could cause an undue burden onto NERC entities. Other regulatory entities, if they have been given such
authority, can develop regulations on their own, to achieve what the SDT has written in R9.1.
Likes

0

Dislikes

0

Response
Bobbi Welch - Midcontinent ISO, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee (SRC) Project 2023-07 TPL-008-1 Draft #2
Answer

No

Document Name
Comment
The SRC[1] observes that Load Loss is addressed in TPL-008, requirement R9 whereas Load Loss is addressed in TPL-001-5.1, Table 1. The SRC
recommends the first sentence of Part 9.3 be stricken from the standard as illustrated below because it is explanatory in nature and adds no value to
the standard. The SRC recommends the first sentence be migrated to the Technical Rationale if the SDT feels it is important to retain.
9.3. The use of Non-Consequential Load Loss as an interim solution in this situation is permitted, provided that each responsible entity documents the
situation causing the problem, alternatives evaluated and takes actions to resolve the situation.
The SRC also expresses concern with Part 9.2, concerning notification to local public service commissions, and proposes this only be required when
Non-Consequential Load Loss is utilized as an element of a corrective action plan (CAP) for the Table P1 contingency. The SRC believes this would be
consistent with existing reporting requirements in TPL-001 and FERC Order 896. See proposed language below:
9.2 Document the alternatives considered and notify the applicable regulatory authorities or governing bodies responsible for retail electric service
issues only when Non-Consequential Load Loss is utilized as an element of a CAP for the Table 1 P1 Contingency.
[1] For purposes of question 5, the IRC SRC includes the following entities: CAISO (only in support of our recommendation regarding Part 9.3), ERCOT,
ISO-NE, MISO, NYISO, PJM and SPP.

Likes

0

Dislikes

0

Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT joins the comments submitted by the IRC SRC and adopts them as its own.
Likes

0

Dislikes

0

Response
Elizabeth Davis - Elizabeth Davis On Behalf of: Thomas Foster, PJM Interconnection, L.L.C., 2; - Elizabeth Davis
Answer

No

Document Name
Comment
PJM supports the IRC SRC comments.
Likes

0

Dislikes

0

Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer

Yes

Document Name
Comment
Recommend updating table references to 1.2.
Likes

0

Dislikes
Response

0

Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

Yes

Document Name
Comment
Requirement #9.3 states:
“Be permitted to utilize Non-Consequential Load Loss as an interim solution, which normally is not permitted in Table 1, in situations that are beyond the
control of the Planning Coordinator or Transmission Planner that prevent the implementation of a Corrective Action Plan in the required timeframe.”
The Extreme Temperature Assessment would have to be performed at least once every 5 years, assessing one year in the Long Term Planning
Horizon.
It is recognized that the details of the extreme heat/cold benchmark temperature events may change over time, and that the underlying assumptions
utilized in the Extreme Temperature Assessment for one of the years in the Long Term Planning Horizon may change over time. CAPs identified in one
Assessment may not be needed in a future Assessment. It may be difficult to pursue expensive CAPs understanding that assumptions may change.
With this in mind, we find it difficult from a compliance perspective to clearly identify what is meant by “in the required timeframe”. This language, while
allowing for flexibility, seems very ambiguous. The Technical Rationale does not elaborate on this point.
We recommend that the SDT clarify what is intended by “in the required timeframe.”
Likes

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0

Response
Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
Likes

0

Dislikes

0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
Likes

0

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0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

Yes

Document Name
Comment
Black Hills Corporation has no concerns with the updated language for requirement R9.
Likes

0

Dislikes

0

Response
Richard Vendetti - NextEra Energy - 5
Answer

Yes

Document Name
Comment
NextEra supports EEI's comments
: EEI offers non-substantive edits in boldface below to Requirement R9.

R9.
Each responsible entity, as identified in Requirement R1, shall develop a Corrective Action Plan(s) (CAPs) when the assessment of a
benchmark planning case, in accordance with Requirement R8 Part 8.1, indicates its portion of the Bulk Electric System is unable to meet performance
requirements for Table 1.1 P0 or P1 Contingencies. For each Corrective Action Plan, the responsible entity shall: [Violation Risk Factor: High] [Time
Horizon: Long-term Planning]
9.1. Make their CAP available and solicit feedback from applicable regulatory authorities or governing bodies responsible for retail electric service
issues.

9.2. Document the alternative(s) considered and notify the applicable regulatory authorities or governing bodies responsible for retail electric service
issues when Non-Consequential Load Loss is utilized as an element of a CAP for the Table 1.1 P1 Contingency.
9.3. Be permitted to utilize Non-Consequential Load Loss as an interim solution, which normally is not permitted in Table 1, in situations that are beyond
the control of the Planning Coordinator or Transmission Planner that prevent the implementation of a Corrective Action Plan in the required timeframe.
The use of Non-Consequential Load Loss as an interim solution in this situation is permitted, provided that each responsible entity documents the
situation causing the problem, alternatives evaluated, and takes actions to resolve the situation.
Likes

0

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0

Response
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer

Yes

Document Name
Comment
In R9.1, Ameren suggests inserting the phrase "and Planning Coordinators" after "governing bodies." Ameren CAPs are typically approved by the
Planning Coordinator through a stakeholder process.
Likes

0

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0

Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI offers non-substantive edits in boldface below to Requirement R9.

R9.
Each responsible entity, as identified in Requirement R1, shall develop a Corrective Action Plan(s) (CAPs) when the assessment of a
benchmark planning case, in accordance with Requirement R8 Part 8.1, indicates its portion of the Bulk Electric System is unable to meet performance
requirements for Table 1.1 P0 or P1 Contingencies. For each Corrective Action Plan, the responsible entity shall: [Violation Risk Factor: High] [Time
Horizon: Long-term Planning]
9.1. Make their CAP available and solicit feedback from applicable regulatory authorities or governing bodies responsible for retail electric service
issues.

9.2. Document the alternative(s) considered and notify the applicable regulatory authorities or governing bodies responsible for retail electric service
issues when Non-Consequential Load Loss is utilized as an element of a CAP for the Table 1.1 P1 Contingency.
9.3. Be permitted to utilize Non-Consequential Load Loss as an interim solution, which normally is not permitted in Table 1, in situations that are beyond
the control of the Planning Coordinator or Transmission Planner that prevent the implementation of a Corrective Action Plan in the required timeframe.
The use of Non-Consequential Load Loss as an interim solution in this situation is permitted, provided that each responsible entity documents the
situation causing the problem, alternatives evaluated, and takes actions to resolve the situation.

Likes

0

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0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

Yes

Document Name
Comment
Please see comments from EEI
Likes

0

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0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
It is challenging to agree due to not knowing the benchmarks to be set by NERC and the number of CAPs that may exist. The benchmarks identified
may not actually be realistic for certain entities depending on locations and could complicate the ability to apply CAPS for unrealistic benchmarks. We
must assume that the process for developing the benchmarks will recognize the complexities that microclimates play on certain locations across the
ERO footprint.
Based on other projects that include developing and implementing CAPs, USV would feel more confident with the proposed modifications if there were
timelines set for the CAPs. Perhaps not in the standard itself, but guidance on timelines could be explained in the technical rationale and include
timelines for implementing CAPs and when entities can utilize backup action plans such as Non-Consequential Load Loss.
Likes
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0
0

Response
Kinte Whitehead - Exelon - 3
Answer

Yes

Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
Likes

0

Dislikes

0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

Yes

Document Name
Comment
PGAE has no comment on the updated R9 Corrective Action Plan.
Likes

0

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0

Response
Robert Blackney - Edison International - Southern California Edison Company - 1
Answer

Yes

Document Name
Comment
See comments submitted by Edison Electric Institute
Likes

0

Dislikes
Response

0

Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Barbara Marion - Dominion - Dominion Resources, Inc. - 5, Group Name Dominion
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Helen Lainis - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Michele Tondalo - United Illuminating Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Greg Sorenson - Greg Sorenson On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Greg Sorenson
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Michele Shafer - New York State Electric & Gas (NYSEG) - 6

Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Apollonia Gonzales - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
John Brewer - National Energy Technology Laboratory - 9 - NA - Not Applicable
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE continues to recommend including a timeframe for which the CAPs need to be developed and submitted for review once the benchmark
planning case study results indicate the System is unable to meet performance requirements.

Texas RE likewise continues to have concerns about the submission of CAPs solely to “applicable regulatory authorities…responsible for retail electric
service.” As an initial matter, it is unclear how this requirement will work in practice and how the ERO could maintain visibility into the CAP review
process. More broadly, since the Reliability Coordinator (RC) is the functional entity responsible for the Reliable Operation of the Bulk Electric System
within the NERC jurisdictional model, has the Wide Area view of the Bulk Electric System, and has the operating tools, processes and procedures,
including the authority to prevent or mitigate emergency operating situations, the CAP should at least be submitted to the RC in addition to applicable
regulatory authorities.

Consistent with this approach, Texas RE recommends the following revision:

9.1 Make their CAPs available and solicit feedback from their Reliability Coordinator and applicable regulatory authorities or governing bodies
responsible for retail electric service issues within 60 days of developing the CAPs.
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0

6. The DT updated Requirement R10 based on comments received. Do you agree with the updated proposed TPL-008-1 Reliability Standard
Requirement R10? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural justification.
Long Island Power Authority

Answer

Yes

Document Name

(if an attachment is provided by submitter)

Comment
Submitter’s comments
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0

# of other submitters who agree with these comments

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0

# of other submitters who disagree with these comments

Response
(Drafting team’s response to submitter’s comments)
John Brewer - National Energy Technology Laboratory - 9 - NA - Not Applicable
Answer

No

Document Name
Comment
(R10) Previous requirements allowed for alternative(s) to be considered. We are suggesting replacing all “possible actions” with “possible action(s)” to allow a single
action to mitigate the consequences and adverse impacts.
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0

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0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

No

Document Name
Comment
The decision to include the escalating phrase “instability, uncontrolled separation, or Cascading” in R10.1, but not 10.2 is confusing. This would indicate
that the benchmark planning cases only require entities to “evaluate and document possible actions” if they rise to the level of significant BES
impact. At a minimum, the DT should provide a clarifying statement to explain this rationale.

Likes

0

Dislikes

0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
Please refer to Question 1 comments.
Likes

0

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0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

No

Document Name
Comment
ITC understands the need for both steady-state and stability studies for the required contingencies. However, ITC makes the following recommendation
for the sensitivity event being evaluated.
R10 should be modified to only require P0 and P1 contingencies be analyzed as part of the standard for the sensitivity event. The remaining
contingencies identified should be left as an option for entities. R10.2 should only be applicable for steady state studies of P0 and P1 for the sensitivity
case. Additionally Table 1 should be modified so that system issues identified during steady state reviews for P0 and P1 be addressed with a CAP. As
currently drafted, completion of the sensitivity case studies are purely an administrative burden on entities completing the studies.
Likes

0

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0

Response
Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer
Document Name
Comment

No

FERC Order 896 Paragraph 113 as part of the Commission Determination states that “NERC may determine whether contingencies P1 through P7
should also apply to the new or modified Reliability Standard, or whether a new set of contingencies should be developed.”
ISO-NE recommends that R10 be removed from the Standard as the FERC Order does not require the inclusion of P2, P4, or P7 contingency
events. The P0 and P1 contingency events have a higher likelihood of occurrence and should remain within the Standard.
Likes

0

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0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

No

Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments:
We see that R10 requires a significant amount of work without providing additional system reliability.
Likes

0

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0

Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
•

•

Likes

The purpose and reliability benefit of R10 is ambiguous. It is understood that P2, P4, P5, & P7 events tend to be lower probability but
documenting possible mitigations every 5 years for these low-probability events in an extreme weather condition appears more administrative
than reliability-based as the requirement is currently written. Reliability Standards should be performance based and impact
reliability. Developing possible actions where mitigation is not required just adds more administrative burden to the PC/TP with no benefit to
reliability as the result.
The exclusion of the P3 & P6 events from these requirements is appropriate. The SDT should consider if specific P2, P4, P5, & P7 events
should likewise be excluded so the standard only addresses those events that must be evaluated and mitigated. A better option would be to
pursue a methodology developed by the PC/TP that is relevant to the benchmark event they are studying as opposed to rigidly referring to
specific P events that may or may not be applicable to the analysis to be performed
0

Dislikes
Response

0

Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer

No

Document Name
Comment
Technical rationale should be assessed for justifying the removal of P2, P4, and especially P7 as well.
Likes

0

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0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

No

Document Name
Comment
Tri-State supports the comments submitted by the MRO NSRF.
Likes

0

Dislikes

0

Response
Matt Lewis - Lower Colorado River Authority - 1
Answer

No

Document Name
Comment
LCRA TSC would like see more clarification on the difference between R9 and R10. How is “evaluate and document possible actions” different then
developing CAPs?
Likes

0

Dislikes

0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1

Answer

No

Document Name
Comment
Minnesota Power supports MRO’s NERC Standards Review Forum’s (NSRF) comments.
Likes

0

Dislikes

0

Response
Teresa Krabe - Lower Colorado River Authority - 5
Answer

No

Document Name
Comment
LCRA would like see more clarification on the difference between R9 and R10. How is “evaluate and document possible actions” different then
developing CAPs?
Likes

0

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0

Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer

No

Document Name
Comment
WECC suggests the DT consider "CAP development" versus “document possible actions”. Possible actions could include “do nothing” which does not
appear to support reliability.
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0

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0

Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment
EEI does not object to the intent of Requirement 10, but we do not agree that entities should be made accountable for developing actions for categories
P2 through P7 because no corrective actions are required under this Reliability Standard beyond categories P0 and P1. It is sufficient for the
responsible entity to conduct the assessments but developing and retaining documentation for mitigations for categories P2 through P7 represents an
unnecessary administrative burden and provides no reliability benefit.

R10. Each responsible entity, as identified in Requirement R1, shall evaluate the Contingency Categories identified in Table 1.1 and document
possible actions for Categories P0 and P1. For Categories P2 through P7, document these categories were analyzed but it is not required to
develop mitigations or retain records of those assessments. Assessments shall be as follows: [Violation Risk Factor: Lower] [Time Horizon:
Longterm Planning]
10.1. Benchmark planning cases where possible actions are designed to mitigate the consequences and adverse impacts when the study results
indicate the System could result in instability, uncontrolled separation, or Cascading for the Table 1 P2, P4, and P7 Contingencies.
10.2. Sensitivity cases where possible actions are designed to mitigate failures to meet the performance requirements in Table 1 for category P0, P1,
Contingencies
Likes

0

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0

Response
Israel Perez - Israel Perez On Behalf of: Laura Somak, Salt River Project, 3, 6, 5, 1; Mathew Weber, Salt River Project, 3, 6, 5, 1; Thomas
Johnson, Salt River Project, 3, 6, 5, 1; Timothy Singh, Salt River Project, 3, 6, 5, 1; - Israel Perez
Answer

No

Document Name
Comment
Define Table 1 in requirement R10.1 and R10.2. Need to clarify or re write what needs to be done for requirement R10.
Likes

0

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0

Response
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment

No

The analysis requirements of Requirement R10 pose a significant burden and produce no significant reliability benefit. Most of the contingencies
analyzed do not require CAPs. It is suggested to remove P2, P4, and P7 from Part 10.2. This lessens the analysis burden while still ensuring sensitivity
cases are analyzed for the Contingencies that require CAPs in the benchmark planning cases. This still accomplishes the FERC directives requiring the
analysis of sensitivity cases.
Likes

0

Dislikes

0

Response
Helen Lainis - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment
We support NPCC TFCP comment
Likes

0

Dislikes

0

Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment
Southern Company appreciates the removal of P5. Technical rationale should be assessed for justifying the removal of P2, P4, and especially P7 as
well.
Likes

0

Dislikes

0

Response
Junji Yamaguchi - Hydro-Quebec (HQ) - 5
Answer
Document Name
Comment

No

We see that R10 requires a significant amount of work without providing additional system reliability. We suggest that this requirement be removed.
Likes

0

Dislikes

0

Response
Kevin Conway - Western Power Pool - 4
Answer

No

Document Name
Comment
Add in language that had been removed from previous version “reduce the likelihood or mitigate the consequences” to align with TPL-001.
Likes

0

Dislikes

0

Response
Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

No

Document Name
Comment
Santee Cooper would like to see the language align more with TPL-001-5 and is concerned about the additional work and the benefit of the analysis to
long term planning horizon.

Likes

0

Dislikes

0

Response
Amy Wilke - American Transmission Company, LLC - 1
Answer
Document Name
Comment

No

ATC supports the MRO NSRF comments.
Likes

0

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0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

No

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and the Midwest Reliability Organization's NERC
Standards Review Forum (MRO NSRF) on question 6
Likes

0

Dislikes

0

Response
Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
Documenting possible actions is insufficient; responsible entities must do something.
Likes

0

Dislikes

0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer
Document Name

No

Comment
SMUD supports the comments submitted by EEI.
Likes

0

Dislikes

0

Response
Robert Jones - Seattle City Light - 1,3,4,5,6
Answer

No

Document Name
Comment
Add in language that had been removed from previous version “reduce the likelihood or mitigate the consequences” to align with TPL-001.
Likes

0

Dislikes

0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

No

Document Name
Comment
Oncor disagrees with R10 as well. The requirement does not give TPs the ability to create CAPs for the listed contingencies.
Likes

0

Dislikes

0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer
Document Name
Comment

No

We see that R10 requires a significant amount of work without providing additional system reliability.
Likes

0

Dislikes

0

Response
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

No

Document Name
Comment
Part 10.1. MRO NSRF requests clarification regarding the objective of TPL-008-1, Part 10.1. What results are to be achieved pursuant to TPL-008-1,
Requirement 10, Part 10.1 that are above and beyond the results achieved pursuant to TPL-001-5.1, Requirement 2, Parts 2.1, 2.2 and 2.7? The two
provisions seem to be very similar and duplicative.

10.1. Benchmark planning cases where possible actions are designed to mitigate the consequences and adverse impacts when the study results
indicate the System could result in instability, uncontrolled separation, or Cascading for the Table 1 P2, P4, and P7 Contingencies.

See also our response to Question #5.
Likes

0

Dislikes

0

Response
Zahid Qayyum - New York Power Authority - 5
Answer

No

Document Name
Comment
NYPA suggest SDT should consider align the language in R10 with that of TPL 001 5.1 for consistency. For instance, SDT can consider retaining the
term “reduce the likelihood” as used in TPL 001-5.1
Likes

0

Dislikes
Response

0

Fon Hiew - NB Power Corporation - New Brunswick Power Transmission Corporation - 5
Answer

No

Document Name
Comment
We see that R10 requires a significant amount of work without providing additional system reliability.
Likes

0

Dislikes

0

Response
Ronald Hoover - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA recommends that R10.1 and R10.2 be modified to include “to reduce the likelihood or mitigate the consequences” to align with TPL-001.
R10.1. Benchmark planning cases where possible actions are designed to reduce the likelihood or mitigate the consequences and adverse impacts
when the study results indicate the System could result in instability, uncontrolled separation, or Cascading for the Table 1 P2, P4, and P7
Contingencies.
R10.2. Sensitivity cases where possible actions are designed to reduce the likelihood or mitigate failures to meet the performance requirements in
Table 1 for category P0, P1, P2, P4, and P7 Contingencies.
Likes

0

Dislikes

0

Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

No

Document Name
Comment
Please refer to our response for comments 3 and 4.
Likes

0

Dislikes

0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

No

Document Name
Comment
CHPD agrees with Western Power Pool’s (WPP) comment.
Likes

1

Dislikes

Jennie Wike, N/A, Wike Jennie
0

Response
Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer

No

Document Name
Comment
Comments:
We see that R10 requires a significant amount of effort and work without any assurance of providing additional system reliability. We suggest that this
requirement and associated testing requirements in R9 be removed.
Likes

0

Dislikes

0

Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
(R10 and R10.1) It is recommended that the requirement for documenting “possible actions” should preserve the right to identify only a single action
(i.e., “possible action(s)”) that would best mitigate the consequence or adverse impact based on the analysis. Otherwise, due to the complex and
comprehensive nature of the analysis and mitigation option review, we believe attempting to document less reliable or less effective solutions in a way
that is clear, so as to avoid any confusion, would be an inefficient and ineffective task.

(R10.2) As noted in the comments associated with R4.2, we do not agree that an increasingly more extreme scenario for purposes of a sensitivity
analysis, is credible. This is especially true for longer term planning horizons when generation additions and retirements, along with transmission
configuration changes and new technologies to be deployed are less detailed.
Likes

0

Dislikes

0

Response
Chelsea Loomis - Western Power Pool - NA - Not Applicable - WECC, Group Name WPP Consortium of Engineers
Answer

No

Document Name
Comment
Add in language that had been removed from previous version “reduce the likelihood or mitigate the consequences” to align with TPL-001.
Likes

0

Dislikes

0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

No

Document Name
Comment
Add in language that was removed from previous verson 'reduce the likelihood or mitigate the consequences" to align with TPL-001-5.
Likes

2

Dislikes

Snohomish County PUD No. 1, 3, Chaney Holly; Jennie Wike, N/A, Wike Jennie
0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer

No

Document Name
Comment
We see that R10 requires a significant amount of work without providing additional system reliability.

Likes

0

Dislikes

0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza
Answer

No

Document Name
Comment
We see that R10 requires a significant amount of work without providing additional system reliability. We suggest that this requirement be removed.
Likes

0

Dislikes

0

Response
Usama Tahir - Seminole Electric Cooperative, Inc. - 3
Answer

No

Document Name
Comment
Likes

0

Dislikes

0

Response
Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

No

Document Name
Comment
Likes

0

Dislikes
Response

0

Robert Blackney - Edison International - Southern California Edison Company - 1
Answer

Yes

Document Name
Comment
See comments submitted by Edison Electric Institute
Likes

0

Dislikes

0

Response
Kinte Whitehead - Exelon - 3
Answer

Yes

Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
Likes

0

Dislikes

0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

Yes

Document Name
Comment
Please see comments from EEI
Likes

0

Dislikes

0

Response
Richard Vendetti - NextEra Energy - 5
Answer

Yes

Document Name
Comment
NextEra supports EEI's comments
EEI does not object to the intent of Requirement 10, but we do not agree that entities should be made accountable for developing actions for categories
P2 through P7 because no corrective actions are required under this Reliability Standard beyond categories P0 and P1. It is sufficient for the
responsible entity to conduct the assessments but developing and retaining documentation for mitigations for categories P2 through P7 represents an
unnecessary administrative burden and provides no reliability benefit.

R10. Each responsible entity, as identified in Requirement R1, shall evaluate the Contingency Categories identified in Table 1.1 and document
possible actions for Categories P0 and P1. For Categories P2 through P7, document these categories were analyzed but it is not required to
develop mitigations or retain records of those assessments. Assessments shall be as follows the following: [Violation Risk Factor: Lower]
[Time Horizon: Longterm Planning]
10.1. Benchmark planning cases where possible actions are designed to mitigate the consequences and adverse impacts when the study results
indicate the System could result in instability, uncontrolled separation, or Cascading for the Table 1 P2, P4, and P7 Contingencies.
10.2. Sensitivity cases where possible actions are designed to mitigate failures to meet the performance requirements in Table 1 for category P0, P1,
P2, P4, and P7 Contingencies
Likes

0

Dislikes

0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

Yes

Document Name
Comment
Black Hills Corporation is aligned with the comments made by EEI, which are in italics below.
‘EEI does not object to the intent of Requirement 10, but we do not agree that entities should be made accountable for developing actions for categories
P2 through P7 because no corrective actions are required under this Reliability Standard beyond categories P0 and P1. It is sufficient for the
responsible entity to conduct the assessments but developing and retaining documentation for mitigations for categories P2 through P7 represents an
unnecessary administrative burden and provides no reliability benefit.

R10. Each responsible entity, as identified in Requirement R1, shall evaluate the Contingency Categories identified in Table 1.1 and document
possible actions for Categories P0 and P1. For Categories P2 through P7, document these categories were analyzed but it is not required to
develop mitigations or retain records of those assessments. Assessments shall be as follows (remove: the following): [Violation Risk Factor:
Lower] [Time Horizon: Longterm Planning]

10.1. Benchmark planning cases where possible actions are designed to mitigate the consequences and adverse impacts when the study results
indicate the System could result in instability, uncontrolled separation, or Cascading for the Table 1 P2, P4, and P7 Contingencies.
10.2. Sensitivity cases where possible actions are designed to mitigate failures to meet the performance requirements in Table 1 for category P0 and
P1 Contingencies’
Likes

0

Dislikes

0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the comments submitted by the EEI for this question.
Likes

0

Dislikes

0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Document Name
Comment

Yes

FirstEnergy supports EEI’s comments which state:
EEI does not object to the intent of Requirement 10, but we do not agree that entities should be made accountable for developing actions for categories
P2 through P7 because no corrective actions are required under this Reliability Standard beyond categories P0 and P1. It is sufficient for the
responsible entity to conduct the assessments but developing and retaining documentation for mitigations for categories P2 through P7 represents an
unnecessary administrative burden and provides no reliability benefit.
R10. Each responsible entity, as identified in Requirement R1, shall evaluate the Contingency Categories identified in Table 1.1 and document
possible actions for Categories P0 and P1. For Categories P2 through P7, document these categories were analyzed but it is not required to
develop mitigations or retain records of those assessments. Assessments shall be as follows the following: [Violation Risk Factor: Lower]
[Time Horizon: Long term Planning]
10.1. Benchmark planning cases where possible actions are designed to mitigate the consequences and adverse impacts when the study results
indicate the System could result in instability, uncontrolled separation, or Cascading for the Table 1 P2, P4, and P7 Contingencies.
10.2. Sensitivity cases where possible actions are designed to mitigate failures to meet the performance requirements in Table 1 for category P0, P1,
P2, P4, and P7 Contingencies

Likes

0

Dislikes

0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
Duke Energy agrees with and recommends implementation of EEI comments.
Likes

0

Dislikes

0

Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer

Yes

Document Name
Comment
Recommend updating table references to 1.2.

Likes

0

Dislikes

0

Response
Apollonia Gonzales - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Elizabeth Davis - Elizabeth Davis On Behalf of: Thomas Foster, PJM Interconnection, L.L.C., 2; - Elizabeth Davis
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Bobbi Welch - Midcontinent ISO, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee (SRC) Project 2023-07 TPL-008-1 Draft #2

Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Ben Hammer - Western Area Power Administration - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Greg Sorenson - Greg Sorenson On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Greg Sorenson
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Michele Tondalo - United Illuminating Co. - 1

Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Mike Magruder - Avista - Avista Corporation - 1
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
Robert Follini - Avista - Avista Corporation - 3
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Barbara Marion - Dominion - Dominion Resources, Inc. - 5, Group Name Dominion
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

7. The DT split out Table 1 into parts for better readability. Do you agree with the updated layout of Table 1? If you do not agree, please
provide your recommendation and technical justification.
Long Island Power Authority

Answer

No

Document Name

(if an attachment is provided by submitter)

Comment
a)
The updated layout of Table 1 is helpful. Note however, that the text of applicable requirements which reference “Table 1”
should be modified to reflect reference to either “Table 1.1”, “Table 1.2” or “Table 1.3”.
b)
We observe that Table 1.1 (Contingency Category) references a Footnote 2. Footnote 2 states applicable contingencies
would be Facilities 200 kV and above.
This is an important distinction, and we recommend that that this detail be included within the actual text of Requirement #7.
c)

Regarding Footnote 2b, the wording of the text is confusing.

We would recommend to edit the wording of Footnote 2b to be more consistent with TPL-001-5.1, footnote 11, such as:
“For P7 planning events that have at least one 200 kV voltage and above Facility that shares a common structure for at least 1
mile.”
d)
Additionally, Footnote 2b should be referenced within Table 1.1, next to the P7 category Event item 1 (similar to TPL-0015.1 Table 1 for P7 events).
e)

Questions Regarding footnote 2:

We interpret that footnote 2 is meant to be a filter (>200kV) or screening for identifying events that would have a more severe
impact on the BES. We also interpret that as part of the Extreme Temperature Assessment, an entity is responsible for monitoring
their entire BES.
Is this interpretation correct? Some elaboration within the Technical Rationale would be helpful.
Likes

0

Dislikes

# of other submitters who agree with these comments
0

# of other submitters who disagree with these comments

Response
(Drafting team’s response to submitter’s comments)
Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza
Answer

No

Document Name
Comment
Consistent with comments above, Table 1 should be updated to remove P2, P4, and P7 Contingencies.
Likes

0

Dislikes

0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer

No

Document Name
Comment
Consistent with comments above, Table 1 should be updated to remove P2, P4, and P7 Contingencies.
Likes

0

Dislikes

0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

No

Document Name
Comment
The new table approach was confusing. Matching the formatting to Table 1 in TPL-001-5.1 would make good sense here.

Likes
Dislikes

2

Snohomish County PUD No. 1, 3, Chaney Holly; Jennie Wike, N/A, Wike Jennie
0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

No

Document Name
Comment
List all Planning Events from Table 1 of TPL-001-5 but identify N/A events for TPL-008 rather than including incomplete table.
Likes

0

Dislikes

0

Response
Chelsea Loomis - Western Power Pool - NA - Not Applicable - WECC, Group Name WPP Consortium of Engineers
Answer

No

Document Name
Comment
Matching formatting to TPL 001-5 makes good sense here. Please see attached PNG for suggestion.

Likes

0

Dislikes

0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

No

Document Name

Proposed Table 1.pdf

Comment
CHPD does not agree with the updated layout of Table 1. CHPD recommends combining Table 1.1 and Table 1.2 to keep things more in the flavor of
TPL-001-5 Table 1. See the “Proposed Table 1” attachment for the direction of what CHPD would recommend.
Additionally:
1) Footnote 1 in Table 1.3 (related to faults) does not appear to have an item referencing it in the current Table 1.1 or 1.2 and; 2) for the stability
performance requirement, there is an additional line “The System shall remain stable” for the P0 event; this line does not appear to be coming from any

requirements and does not appear to be discussed elsewhere. It is recommended this line be removed and the P0 requirement for stability is the same
as the P1-P7 language set “Instability, uncontrolled separation, or Cascading, as defined in Requirement R6, shall not occur.”.
Likes

1

Dislikes

Jennie Wike, N/A, Wike Jennie
0

Response
Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

No

Document Name
Comment
a) The updated layout of Table 1 is helpful. Note however, that the text of applicable requirements which reference “Table 1” should be modified to
reflect reference to either “Table 1.1”, “Table 1.2” or “Table 1.3”.
b) We observe that Table 1.1 (Contingency Category) references a Footnote 2. Footnote 2 states applicable contingencies would be Facilities 200 kV
and above.
This is an important distinction, and we recommend that that this detail be included within the actual text of Requirement #7.
c) Regarding Footnote 2b, the wording of the text is confusing.
We would recommend to edit the wording of Footnote 2b to be more consistent with TPL-001-5.1, footnote 11, such as:
“For P7 planning events that have at least one 200 kV voltage and above Facility that shares a common structure for at least 1 mile.”
d) Additionally, Footnote 2b should be referenced within Table 1.1, next to the P7 category Event item 1 (similar to TPL-001-5.1 Table 1 for P7 events).
e) Questions Regarding footnote 2:
We interpret that footnote 2 is meant to be a filter (>200kV) or screening for identifying events that would have a more severe impact on the BES. We
also interpret that as part of the Extreme Temperature Assessment, an entity is responsible for monitoring their entire BES.
Is this interpretation correct? Some elaboration within the Technical Rationale would be helpful.
Likes

0

Dislikes

0

Response
Ronald Hoover - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name

WPP TPL-008 Table 1 Reference.pdf

Comment

BPA agrees with WPP Consortium of Engineers comments to match the format to TPL-001-5. BPA has attached a copy of the table referenced by
WPP.
Likes

0

Dislikes

0

Response
Fon Hiew - NB Power Corporation - New Brunswick Power Transmission Corporation - 5
Answer

No

Document Name
Comment
Consistent with comments above, Table 1 should be updated to remove P2, P4, and P7 Contingencies.
Likes

0

Dislikes

0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer

No

Document Name
Comment
Consistent with comments above, Table 1 should be updated to remove P2, P4, and P7 Contingencies.
Likes

0

Dislikes

0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer
Document Name
Comment

No

Table 1 should be updated to remove P2, P4, and P7 Contingencies. Oncor also agrees that matching the formatting of Table 1 to TPL 001-5 is
appropriate.
Likes

0

Dislikes

0

Response
Robert Jones - Seattle City Light - 1,3,4,5,6
Answer

No

Document Name
Comment
The table should match formatting to TPL 001-5.
Likes

0

Dislikes

0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

No

Document Name
Comment
SMUD supports the comments submitted by the MRO NSRF.
Likes

0

Dislikes

0

Response
Robert Follini - Avista - Avista Corporation - 3
Answer

No

Document Name

2023-07 comment7.png

Comment

Avista offers the following suggested comment for consideration:
Given the intended scope of the project and the technical differences between TPL-001-5, we suggest maintaining consistency between these
standards wherever possible to reduce confusion.
To reduce confusion and create consistency, match formatting to TPL-001-5 using suggested table formatting below.

Likes

0

Dislikes

0

Response
Kevin Conway - Western Power Pool - 4
Answer

No

Document Name
Comment
Matching formatting to TPL 001-5 makes good sense here.

Likes

0

Dislikes

0

Response
Junji Yamaguchi - Hydro-Quebec (HQ) - 5
Answer

No

Document Name
Comment
Comments: Consistent with comments above, Table 1 should be updated to remove P2, P4, and P7 Contingencies.
Likes

0

Dislikes

0

Response
Helen Lainis - Independent Electricity System Operator - 2

Answer

No

Document Name
Comment
We support NPCC TFCP comment
Likes

0

Dislikes

0

Response
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer

No

Document Name

TPL-008-1-proposed-Table-1.docx

Comment
We appreciate the work of the DT to increase readability of Table 1. We recommend changes in the attached document to improve upon the revisions.
Likes

0

Dislikes

0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

No

Document Name

Table Example.png

Comment
Given the intended scope of the project and the technical differences between TPL-001-5, we suggest maintaining consistency between these
standards wherever possible to reduce confusion.
To reduce confusion and create consistency, match formatting to TPL-001-5 using suggested table formatting attached.

Likes

0

Dislikes

0

Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford

Answer

No

Document Name
Comment
Performance criteria should be included in the table.
Likes

0

Dislikes

0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

No

Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments:
Consistent with comments above, Table 1 should be updated to remove P2, P4, and P7 Contingencies.
Likes

0

Dislikes

0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
Please refer to Question 1 comments.
Likes

0

Dislikes

0

Response
John Brewer - National Energy Technology Laboratory - 9 - NA - Not Applicable
Answer

No

Document Name
Comment
By splitting out Table 1, the footnotes became Table 1.3. If the Table 1 split is selected for the final version of the standard, please move the footnotes after Table 1.1
because that is the only table with footnotes. Furthermore, check the footnote numbers. Footnote #1 is missing as a reference in the tables 1.1 and 1.2.
Likes

0

Dislikes

0

Response
Usama Tahir - Seminole Electric Cooperative, Inc. - 3
Answer

No

Document Name
Comment
Likes

0

Dislikes

0

Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer

Yes

Document Name
Comment
references in requirements should reference table 1.1 or 1.2 instead of only table 1
Likes

0

Dislikes

0

Response
Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer
Document Name
Comment

Yes

Footnote 1 is missing from table 1.1 & 1.2 and is defined in table 1.3.
Likes

0

Dislikes

0

Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

Yes

Document Name
Comment
Please refer to appropriate table number either Table 1.1 or Table 1.2 in the requirements.
Likes

0

Dislikes

0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
Duke Energy agrees with and recommends implementation of EEI comments.
Likes

0

Dislikes

0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Document Name
Comment
No additional comments.

Yes

Likes

0

Dislikes

0

Response
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

Yes

Document Name
Comment
MRO NSRF supports the format for Table 1; however, has the following questions and comments.
Does Footnote 2 in Table 1.3 (200kV and greater) apply everywhere? The MRO NSRF requests the SDT clarify this in the standard.
Steady state performance requirements have stability requirements for P2, P4, P7. Voltage collapse (cascading) can be identified, but not instability or
uncontrolled separation. This would require a dynamic study.
The MRO NSRF disagrees with the Table 1 reference to extreme conditions in a base model.
Is there an opportunity for TPL-008-1, Table 1.1 to reference TPL-001-5.1 instead? Only TPL-008-1, Table 1.2 shows information specific and unique to
TPL-008.
Likes

1

Dislikes

Scott Brame, N/A, Brame Scott
0

Response
Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon agrees with the updated layout of Table 1. However, in Table 1.2, we believe the sentence “The System shall remain stable.” should either be
removed or added to P1 Stability Performance Requirements so both P0 and P1 are consistent. Additionally, we noticed that footnote 1 in Table 1.3 is
not referenced in any of the tables.
Additionally, Exelon supports the comments submitted by the EEI for this question.
Likes

0

Dislikes
Response

0

Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

Yes

Document Name
Comment
Black Hills Corporation has no concerns with the updated layout of Table 1.
Likes

0

Dislikes

0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

Yes

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) and the Midwest Reliability Organization's NERC
Standards Review Forum (MRO NSRF) on question 7
Likes

0

Dislikes

0

Response
Amy Wilke - American Transmission Company, LLC - 1

Answer

Yes

Document Name
Comment
Footnote 1 does not appear to be linked to ‘Fault Type’ in Table 1.1.
ATC supports the MRO NSRF comments.
Likes

0

Dislikes

0

Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

Yes

Document Name
Comment
Table 1.2 provides much better visualization and clarification of expectations.
Please clarify the meaning of “The System shall remain stable”, as well as the distinction between the use of “System” and “within an Interconnection”.
Likes

0

Dislikes

0

Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI does not have any concerns with the revised labelling of the Tables but references to the tables should also be updated for clarity.
Likes

0

Dislikes

0

Response
Kinte Whitehead - Exelon - 3

Answer

Yes

Document Name
Comment
Exelon agrees with the updated layout of Table 1. However, in Table 1.2, we believe the sentence “The System shall remain stable.” should either be
removed or added to P1 Stability Performance Requirements so both P0 and P1 are consistent. Additionally, we noticed that footnote 1 in Table 1.3 is
not referenced in any of the tables.
Additionally, Exelon supports the comments submitted by the EEI for this question.

Likes

0

Dislikes

0

Response
Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer

Yes

Document Name
Comment
ISO-NE is satisfied with the format of Table 1 with the recommendation of removing P2 and greater contingencies as FERC Order 896 Paragraph 113
as part of the Commission Determination states that “NERC may determine whether contingencies P1 through P7 should also apply to the new or
modified Reliability Standard, or whether a new set of contingencies should be developed.”.
The FERC Order does not require the inclusion of P2, P4, or P7 contingency events. The P0 and P1 contingency events have a higher likelihood of
occurrence and should remain within the Standard.
ISO-NE recommends removing the P2, P4 and P7 events from the Table or eliminating the need to perform analysis on those events from the
Requirements.
Likes

0

Dislikes

0

Response
Bobbi Welch - Midcontinent ISO, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee (SRC) Project 2023-07 TPL-008-1 Draft #2
Answer
Document Name
Comment

Yes

The SRC supports the Table 1 format. Is there an opportunity for TPL-008-1, Table 1.1 to reference TPL-001-5.1 instead? Only TPL-008-1, Table 1.2
shows information specific and unique to TPL-008.
Steady state performance requirements have stability requirements for P2, P4, P7. Voltage collapse (cascading) can be identified, but not instability or
uncontrolled separation. This would require a dynamic study.
How does the SDT define how to determine stability performance requirements for P0 events? Currently it says that the system shall remain stable,
and that instability, uncontrolled separation and cascading shall not occur, but how would those things occur for a P0 event?
Likes

0

Dislikes

0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

Yes

Document Name
Comment
PGAE agrees with the updated layout of Table 1.
Likes

0

Dislikes

0

Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
ERCOT joins the comments submitted by the IRC SRC and adopts them as its own.
Likes

0

Dislikes

0

Response
Elizabeth Davis - Elizabeth Davis On Behalf of: Thomas Foster, PJM Interconnection, L.L.C., 2; - Elizabeth Davis
Answer

Yes

Document Name
Comment
PJM supports the IRC SRC comments.
Likes

0

Dislikes

0

Response
Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Zahid Qayyum - New York Power Authority - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Donald Lock - Talen Generation, LLC - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Barbara Marion - Dominion - Dominion Resources, Inc. - 5, Group Name Dominion
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Michele Tondalo - United Illuminating Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Israel Perez - Israel Perez On Behalf of: Laura Somak, Salt River Project, 3, 6, 5, 1; Mathew Weber, Salt River Project, 3, 6, 5, 1; Thomas
Johnson, Salt River Project, 3, 6, 5, 1; Timothy Singh, Salt River Project, 3, 6, 5, 1; - Israel Perez
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Teresa Krabe - Lower Colorado River Authority - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Greg Sorenson - Greg Sorenson On Behalf of: Tyler Schwendiman, ReliabilityFirst , 10; - Greg Sorenson
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Matt Lewis - Lower Colorado River Authority - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

Response
Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Ben Hammer - Western Area Power Administration - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Apollonia Gonzales - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer
Document Name

Yes

Comment
Likes

0

Dislikes

0

Response
Richard Vendetti - NextEra Energy - 5
Answer
Document Name
Comment
NetEra supports EEI's comments
EEI does not have any concerns with the revised labelling of the Tables but references to the tables should also be updated for clarity.
Likes

0

Dislikes

0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE noticed multiple requirements in the standard refers to Table 1 and it is not clear which table is referenced (Table 1.1, Table 1.2 or Table
1.3)? Texas RE recommends the SDT consider making changes to reference the appropriate Table in each of the requirements. Texas RE also
recommends that the column headers be carried over onto each page of the tables.
Likes

0

Dislikes

0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment

Please see comments from EEI
Likes

0

Dislikes

0

Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Document Name
Comment
N/C
Likes

0

Dislikes

0

Response
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer
Document Name
Comment
N/A
Likes

0

Dislikes

0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer
Document Name
Comment
ITC does not have concerns with the layout of Table 1.

Likes

0

Dislikes
Response

0

8. The DT believes proposed modifications in TPL-008-1 provide entities with flexibility to meet the reliability objectives in a cost-effective
manner. Do you agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost-effective approaches,
please provide your recommendation and, if appropriate, technical or procedural justification.
Long Island Power Authority

Answer

Yes

Document Name

(if an attachment is provided by submitter)

Comment
Submitter’s comments
Likes

0

# of other submitters who agree with these comments

Dislikes

0

# of other submitters who disagree with these comments

Response
(Drafting team’s response to submitter’s comments)
John Brewer - National Energy Technology Laboratory - 9 - NA - Not Applicable
Answer

No

Document Name
Comment

In general, the modifications in TPL-008-1 are a step in the right direction to provide entities with the flexibility to meet the reliability
objectives cost-effectively. However, some concerns remain.
Likes

0

Dislikes

0

Response
Elizabeth Davis - Elizabeth Davis On Behalf of: Thomas Foster, PJM Interconnection, L.L.C., 2; - Elizabeth Davis
Answer

No

Document Name
Comment
PJM supports the IRC SRC comments.
Likes

0

Dislikes

0

Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT joins the comments submitted by the IRC SRC and adopts them as its own.
Likes

0

Dislikes

0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

No

Document Name
Comment
Benchmarking extreme events should be considered a “sensitivity” case to normal Transmission Planning long-term cases. PGAE agrees that
additional sensitivity cases to alter Gen/Load/Transfer may be prudent, however, a discrete Requirement for assessing sensitivity cases on top of the
“sensitivity” cases of extreme weather conditions do not seem cost-effective.
Likes

0

Dislikes

0

Response
Bobbi Welch - Midcontinent ISO, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee (SRC) Project 2023-07 TPL-008-1 Draft #2
Answer

No

Document Name
Comment
The SRC believes TPL-008 will require four additional cases be added to the case build process:
1. Summer benchmark planning case

2. Summer sensitivity case
3. Winter benchmark planning case
4. Winter sensitivity case
The Eastern Interconnection Reliability Assessment Group (ERAG) Multi-Regional Modeling Working Group (MMWG) is likely the group that will
coordinate interregional case builds for entities in the Eastern Interconnection, so these cases will be IN ADDITION TO existing case requirements.
Also, extreme temperature sets will require additional data collection from generator owners through MOD-032. Once the temperature sets are known,
PCs will need to issue a data request to generators requesting they provide:
1) the unit’s ability to operate at that extreme temperature, and
2) if able, the machine’s capability.
Further, the interchange coordination through the ERAG MMWG process only considers transactions that have confirmed annual firm transmission
service along the entire path from source to sink and have a firm energy contract for the resource. As these transactions do not currently include
temperature, that adds an additional layer of complexity to the development of these cases.
These are all non-trivial workload additions. For the Eastern Interconnection, the current funding of ERAG may be insufficient to accommodate model
building for all the scenarios listed above. Therefore, ERAG will likely need to increase its fees to accomplish this work. In addition, PCs will likely need
to hire more people to perform the studies.
Finding an effective and efficient process to meet the requirements of Order 896 is paramount to the success of this standard. The drafting team must
be cognizant of the implications of workload on industry to ensure there is value-added for investing in these additional resources.

Likes

0

Dislikes

0

Response
Usama Tahir - Seminole Electric Cooperative, Inc. - 3
Answer

No

Document Name
Comment
The TPL-001 studies are performed every year. The TPL-008 study will be performed at a minimum every 5 years. The DT should look at an approach
that will reduce redundancy and overlap in testing between the TPL-008 and TPL-001 studies in order to save costs to customers.
Likes

0

Dislikes

0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE

Answer

No

Document Name
Comment
There is an associated cost impact with increasing experienced Transmission Planning resources for the additional work this new standard will require.
Likes

0

Dislikes

0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

No

Document Name
Comment
ITC has concerns with the study scope for the sensitivity event. While ITC agrees that information can be gained from these studies, ITC believes that
in most areas they will not result in any reliability benefit for the grid. ITC recommends a reduction in the required studies for the sensitivity event to only
requiring steady state P0 and P1 studies. ITC also recommends that a CAP is also required when the system is unable to meet performance
expectations. With these changes, less overall study work is required and additional reliability benefit will be obtained.
ITC also requests clarification be added in terms of footnote 1. The footnote identifies normal fault clearing. Is this what is intended for the study?
Should this footnote be modified to consider the actual expected performance of the system to faults based on the weather event being studied.
Likes

0

Dislikes

0

Response
Ben Hammer - Western Area Power Administration - 1
Answer

No

Document Name
Comment
WAPA believes the TPL-008 changes will require additional cases be added to the case build process. Also, extreme temperature sets will require
additional data collection from generator owners through MOD-032. Once the temperature sets are known, PCs will need to issue a data request to
generators to provide:
1) the unit’s ability to operate at that extreme temperature, and
2) if able, the machine’s capability.

Likes

0

Dislikes

0

Response
Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer

No

Document Name
Comment
ISO-NE does not agree with the requirements to perform Sensitivity Case studies in 4.2, 8.2 and 10.2. The results of Sensitivity Case studies are not
required to be used per the current Standard language. This seems to be strictly an administrative action, which would burden the PCs with cost of time
and resources to conduct the studies and does not provide reliability benefit for the BES.
R7 requires testing of all the events listed in Table 1, however R9 only requires the development of CAPs for the P0 and P1 contingencies. ISO-NE
recommends modifying Table 1 to only include P0 and P1 events.
Likes

0

Dislikes

0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

No

Document Name
Comment
See comments providded by NPCC Regional Standards Committee.

Likes

0

Dislikes

0

Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer
Document Name
Comment

No

•

The attempt for flexibility is appreciated but this standard falls significantly short of something that is clear and allows the PC/TP to appropriately
plan to meet reliability goals. The inclusion of outside entity reviews of CAPs offers the reviewer flexibility as there are no bounds provided to
them. The PC/TP, however is potentially subjected to subjective reviews that have no framework with which the PC/TP can effectively respond.

Likes

0

Dislikes

0

Response
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer

No

Document Name
Comment
SPP has a concern about the cost-effectiveness for this project.
From our perspective, it’s unclear on how the proposed modifications provides entities the flexibility to meet the reliability objectives in a cost effective
manner. .
SPP recommends that the drafting team work with NERC staff revise the SAR development to include cost effective language to help industry get a
better understanding of the cost effectiveness on implementing this standard.
Likes

0

Dislikes

0

Response
Rebika Yitna - Rebika Yitna On Behalf of: David Weekley, MEAG Power, 3, 1; Roger Brand, MEAG Power, 3, 1; - Rebika Yitna
Answer

No

Document Name
Comment
The language requiring entities to solicit feedback from regulatory authorities and governing bodies, in R9.1, may be removed from the standard to
make it cost-effective. Requiring CAP and installation of equipment is likely not as cost effective as implementing operational procedures
Likes

0

Dislikes

0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1

Answer

No

Document Name
Comment
Tri-State supports the comments submitted by the MRO NSRF.
Likes

0

Dislikes

0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

No

Document Name
Comment
Minnesota Power supports MRO’s NERC Standards Review Forum’s (NSRF) comments.
Likes

0

Dislikes

0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

No

Document Name
Comment
Suggest clarification that operational procedures may constitute an appropriate CAP.
Likes

0

Dislikes

0

Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name

No

Comment
The requirement to solicit CAP feedback from regulatory authorities and governing bodies raises concern about how flexibility might otherwise be limited
outside of the direct influence of the standard. It is Southern Company’s recommendation that the language requiring entities to solicit feedback from
regulatory authorities and governing bodies, in R9.1, should be removed from the standard.
Likes

0

Dislikes

0

Response
Junji Yamaguchi - Hydro-Quebec (HQ) - 5
Answer

No

Document Name
Comment
see comments in other sections.
Likes

0

Dislikes

0

Response
Kevin Conway - Western Power Pool - 4
Answer

No

Document Name
Comment
Requiring CAP and installation of equipment based off NERC TPL 008 is likely not as cost-effective as implementing operational procedures
Likes

0

Dislikes

0

Response
Robert Follini - Avista - Avista Corporation - 3
Answer
Document Name
Comment

No

Avista offers the following suggested comments for consideration:
Avista suggests clarification that operational procedures may constitute an appropriate CAP.
Likes

0

Dislikes

0

Response
Amy Wilke - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
ATC supports the MRO NSRF comments.
Likes

0

Dislikes

0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

No

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Midwest Reliability Organization's NERC Standards Review Forum (MRO NSRF)
on question 8
Likes

0

Dislikes

0

Response
Barbara Marion - Dominion - Dominion Resources, Inc. - 5, Group Name Dominion
Answer
Document Name
Comment

No

There are concerns over the CAP as well as ambiguity in R2.
Likes

0

Dislikes

0

Response
Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
See our comments above
Likes

0

Dislikes

0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

No

Document Name
Comment
SMUD does not believe it is cost effective. The additional costs to maintain the necessary base cases and perform sensitivity studies of rare events that
require no corrective actions is unnecessary and provides no reliability gains.
Likes

0

Dislikes

0

Response
Robert Jones - Seattle City Light - 1,3,4,5,6
Answer
Document Name
Comment

No

Requiring a CAP is likely not as cost-effective as implementing operational procedures.
Likes

0

Dislikes

0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

No

Document Name
Comment
The timeline should not start until the ERO has developed and shared the benchmark event library. Because of the complexity of the required study, the
proposed standard is written to employ a five-year process. Final implementation of the proposed standard should be five years after the ERO has
developed the benchmark event library.
Likes

0

Dislikes

0

Response
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

No

Document Name
Comment
The MRO NSRF believes TPL-008 will require eight additional cases be added to the case build process:
1. Summer benchmark power flow
2. Summer sensitivity power flow
3. Summer benchmark dynamics
4. Summer sensitivity dynamics
5. Winter benchmark power flow
6. Winter sensitivity power flow
7. Winter benchmark dynamics
8. Winter sensitivity dynamics

MMWG is likely going to be the group to coordinate interregional case builds, so these cases will be IN ADDITION TO existing case requirements. Also,
extreme temperature sets will require additional data collection from generator owners through MOD-032. Once the temperature sets are known, PCs
will need to issue a data request to generators to provide:
1) the unit’s ability to operate at that extreme temperature, and
2) if able, the machine’s capability.
These are all non-trivial workload additions. Current funding of ERAG may be insufficient to accommodate model building for all the scenarios listed
above. Therefore, ERAG will likely need to increase its fees to accomplish this work. In addition, PCs will likely need to hire more people to perform the
studies.

Likes

1

Dislikes

Scott Brame, N/A, Brame Scott
0

Response
Zahid Qayyum - New York Power Authority - 5
Answer

No

Document Name
Comment
• NYPA will need more information to adequately assess the cost effectiveness of the proposed approach.
Likes

0

Dislikes

0

Response
Ronald Hoover - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA does not believe it is cost effective. It is cost prohibitive to make capital investments for multiple contingency events during extreme
temperatures. BPA believes it is more appropriate to deal with such scenarios in operating horizon through operating plans
Likes

0

Dislikes
Response

0

Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

No

Document Name
Comment
We believe performing sensitivity studies is unnecessary for the benchmarked extreme temperature scenarios. It is purely administrative and adds no
value to the reliability since nothing expected to do with the the study results other than documenting the possible actions.
Likes

0

Dislikes

0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

No

Document Name
Comment
CHPD agrees with WPP’s comment.
Likes

1

Dislikes

Jennie Wike, N/A, Wike Jennie
0

Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
At this time, due to the number of requirements that we do not agree with, we are unable to fully agree that this standard provides the necessary
flexibility to meet the reliability objectives in a cost-effective manner.
Likes

0

Dislikes
Response

0

Chelsea Loomis - Western Power Pool - NA - Not Applicable - WECC, Group Name WPP Consortium of Engineers
Answer

No

Document Name
Comment
Requiring CAP and installation of equipment based off NERC TPL 008 is likely not as cost-effective as implementing operational procedures
Likes

0

Dislikes

0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

No

Document Name
Comment
Requiring CAP and installation of equipment is likely not as cost effective as implementing operational procedures.
Likes

2

Dislikes

Snohomish County PUD No. 1, 3, Chaney Holly; Jennie Wike, N/A, Wike Jennie
0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer

No

Document Name
Comment
See other answers.
Likes

0

Dislikes

0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza
Answer

No

Document Name
Comment
see comments in other sections
Likes

0

Dislikes

0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer

No

Document Name
Comment
Likes

0

Dislikes

0

Response
Fon Hiew - NB Power Corporation - New Brunswick Power Transmission Corporation - 5
Answer

No

Document Name
Comment
Likes

0

Dislikes

0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer
Document Name
Comment
None

Yes

Likes

0

Dislikes

0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
Comment
FE has no comment toward the cost-effectiveness of this proposal
Likes

0

Dislikes

0

Response
Apollonia Gonzales - PNM Resources - Public Service Company of New Mexico - 1,3,5 - WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Kinte Whitehead - Exelon - 3
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Matt Lewis - Lower Colorado River Authority - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Teresa Krabe - Lower Colorado River Authority - 5
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Israel Perez - Israel Perez On Behalf of: Laura Somak, Salt River Project, 3, 6, 5, 1; Mathew Weber, Salt River Project, 3, 6, 5, 1; Thomas
Johnson, Salt River Project, 3, 6, 5, 1; Timothy Singh, Salt River Project, 3, 6, 5, 1; - Israel Perez
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Michele Tondalo - United Illuminating Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Document Name
Comment
N/C
Likes

0

Dislikes

0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
Please see comments from EEI
Likes

0

Dislikes
Response

0

Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer
Document Name
Comment
Ameren has no comments on the cost effectiveness of the project.
Likes

0

Dislikes

0

Response
Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
Without including the framework and criteria for benchmark events in the standard, it is impossible to assess the cost-effectiveness or the reliability
objectives. While the DT does not need to include detailed weather data in the standard, it must include parameters such as: the duration of historical
meteorological data to use, the likelihood/probability of the events to be studied, the granularity of data required, etc.
Likes

0

Dislikes

0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
Document Name
Comment
Black Hills Corporation will not comment on cost effectiveness.
Likes

0

Dislikes
Response

0

Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
Duke Energy does not comment on costs.
Likes

0

Dislikes
Response

0

9. Provide any additional comments for the standard drafting team to consider, including the provided technical rationale document, if
desired.
Long Island Power Authority

Answer
Document Name
Comment
Comment on the Implementation Plan:
From the Implementation Plan (IP), the graphic on page 3 of the IP does not match the text on page 2. In the graphic, it appears
that the timeline is based on governmental authority approval, and not on when TPL-008-1 goes into effect.
Page 2 of the IP states:
Phased-In Compliance Dates
Compliance Date for TPL-008-1 Requirement R1
Entities shall be required to comply with Requirement R1 upon the effective date of Reliability Standard TPL-008-1.
Compliance Date for TPL-008-1 Requirements R2, R3, R4, R5, R6
Entities shall not be required to comply with Requirements R2, R3, R4, R5, and R6 until thirty-six (36) months after the effective
date of Reliability Standard TPL-008-1.
Compliance Date for TPL-008-1 Requirements R7, R8, R9, R10, R11
Entities shall not be required to comply with Requirements R7, R8, R9, R10, R11 until sixty (60) months after the effective date of
Reliability Standard TPL-008-1.
To match the text on page 2, our interpretation is that the graphic on page 3 should be modified as shown below.

Comment on Requirement #11
Requirement #11 states:
“Each responsible entity, as identified in Requirement R1, shall provide its Extreme Temperature Assessment results within 60
calendar days of a request to any functional entity that has a reliability related need and submits a written request for the
information.”
This could be interpreted in different ways.
We would recommend the SDT consider modifying the wording (see TPL-001-5.1 Req #8 for reference) and timeframe to be more
consistent with TPL-001-5.1 Req #, 8 as follows:
“Each responsible entity, as identified in Requirement R1, shall provide its latest completed Extreme Temperature Assessment
results within 90 calendar days of a request to any functional entity that has a reliability related need and submits a written
request for the information.”

Likes

0

Dislikes

# of other submitters who agree with these comments
0

# of other submitters who disagree with these comments

Response
(Drafting team’s response to submitter’s comments)
Chantal Mazza - Chantal Mazza On Behalf of: Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal Mazza
Answer
Document Name
Comment
1.
Facility Owners (FOs) have an important role in developing and implement corrective action plans. The document does not acknowledge the role
of the FO explicitly. The FO ultimately has the accountability to present CAP and associated investments and cost to its regulatory body for retail
service. We suggest the standard make this explicitly clear.
2.
In certain jurisdiction, extreme temperature ratings have been established, but that is not necessarily the case in all jurisdictions. Will facility
owners be required to establish extreme cold or warm temperature ratings for this standard?
Likes

0

Dislikes

0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer
Document Name
Comment
Facility Owners (FOs) have an important role in developing and implement corrective action plans. The document does not acknowledge the role of the
FO explicitly. The FO ultimately has the accountability to present CAP and associated investments and cost to its regulatory body for retail service. We
suggest the standard make this explicitly clear.
In certain jurisdiction, extreme temperature ratings have been established, but that is not necessarily the case in all jurisdictions. Will facility owners be
required to establish extreme cold or warm temperature ratings for this standard?
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Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
Document Name
Comment

To remain consistent with TPL-001 and the definition of the Extreme Temperature Assessment, “Bulk Power System” should be refined to “Bulk Electric
System” in the purpose statement of this standard.
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Srikanth Chennupati - Entergy - Entergy Services, Inc. - 1,3,5,6 - SERC
Answer
Document Name
Comment
The implementation plan should allow additional time beyond the five-year assessment schedule for the first assessment to be completed. This will
allow time for benchmark temperature events to be identified and developed by the ERO & industry. This will also provide leeway for any issues that
may arise in implementing this large-scale and complex model building and study process that will require new collaboration processes between
Planning Coordinators.
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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Document Name
Comment
(R11) We do not agree with R11. Although the comment document does not appear to request input for R11, we recommend that the “results” only
include the assessments as contemplated in R9, for which Corrective Action Plans will be developed. Since the “possible actions” in R10 are suggested
to be useful for reference only, per the Technical Rationale document, and are not required to have Corrective Action Plans, we believe sharing this
reference information would be an inefficient and ineffective task, and likely to cause more confusion that clarity.
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Lidija Efremova - Lidija Efremova On Behalf of: Emma Halilovic, Hydro One Networks, Inc., 1; - Lidija Efremova
Answer

Document Name
Comment
Comments:
1. The document does not acknowledge the role of the facility owner explicitly. Facility Owners (FO) have an important role in developing and
implement corrective action plans. PC cannot and should NOT come up with requirements without involving the FO. As an example, the IESO should
not be allowed to come up for requirements for extreme weather without full alignment with HONI, that needs to spend the money and provision for
emergency response and replacement for every event. In some jurisdictions, the FO ultimately has the accountability to present CAP and associated
investments and cost to its regulatory body for retail service. We suggest the standard make this explicitly clear.
2. NERC and/or FERC should only direct coordination and alignment and not specific actions. The local PC/TO/BA can determine what the local
needs and responses should be based on a consistent framework for the control area.
3. In Ontario, we have updated and derated equipment ratings by taking extreme temperatures into account; for example, for transmission line we
have gone from 30C to 35C based on regional temperatures. In addition, we also consider extreme weather correction factors both for winter and
summer. For this exercise/standard, would facility owner need to establish further extreme ratings such as 40C or 45C? This will be unmanageable and
provide skewed results and double counting.
4. Are the benchmark events considering regional-specific extremes? We are interested in seeing how Canadian, provincial attributes are considered
within the ERO benchmark library. It is extremely important that Canadian benchmarks are adequately reflected and/or provide flexibility for Canadian
to make changes to the ERO benchmark library.
5. We appreciate and agree with the draft standard for assessment of extreme weather conditions using normal contingencies. However, we would
not support an assessment with required CAP using any type of extreme contingencies.
6. The benchmarking and baselining of the events that one should consider is a necessary step as some jurisdictions/utilities may not want to take
any risk and ask for a lot of funding and others may be more balanced and ask for less funding. Assessing to a reasonable risk level needs to be
consistent.

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Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
Document Name
Comment
Industry have not been provided NERC’s proposed set of benchmark events so that we may provide meaningful feedback during this standard
development process. We continue to have concerns about the benchmark library and the process to include and update events.

On a positive note, while we have not seen such materials included in this standard development process, CHPD appreciates members of the SDT
have reached out to our region regarding the benchmark library, and we have been able to provide dialogue to the SDT via this outreach. This outreach
by the SDT members is appreciated and commendable.
Regarding outages – we see the SDT’s comment and response to “All lines in Service”, but we do not see clarification in the standard itself along these
lines. CHPD requests clarity from the SDT on whether this is the expectation (in which case this should be specifically called out in requirements) or if
this is more a N-0 all lines in service instance, in which case the baseline scenario would not have outages.
The approach in TPL-001-5 R2.1.4. regarding planned outages has precedence in the transmission planning realm.
TPL-001-5.1 R2.1.4 Language:
When known outage(s) of generation or Transmission Facility(ies) are planned in the Near-Term Planning Horizon, the impact of selected known
outages on System performance shall be assessed. These known outage(s) shall be selected for assessment consistent with a documented outage
coordination procedure or technical rationale by the Planning Coordinator or Transmission Planner. Known outage(s) shall not be excluded solely based
upon outage duration. The assessment shall be performed for the P0 and P1 categories identified in Table 1 with the System peak or Off-Peak
conditions that the System is expected to experience when the known outage(s) are planned. This assessment shall include, at a minimum known
outages expected to produce more severe System impacts on the Planning Coordinator or Transmission Planner’s portion of the BES. Past or current
studies may support the selection of known outage(s), if the study(s) has comparable post-Contingency System conditions and TPL-001-5.1 —
Transmission System Planning Performance Requirements Page 3 of 32 configuration such as those following P3 or P6 category events in Table 1.
If planned outages instead of weather-related historic outages are the intent, a proposed language selection for TPL-008, based on TPL-001-5.1 R2.1.4
could be:
When known outage(s) of generation or Transmission Facility(ies) are planned in the Long-Term Transmission Planning Horizon, the impact of selected
known outages on System performance shall be assessed. These known outage(s) shall be selected for assessment consistent with a documented
outage coordination procedure or technical rationale by the Planning Coordinator or Transmission Planner. Known outage(s) shall not be excluded
solely based upon outage duration. The assessment shall be performed for the P0 and P1 categories identified in Table 1 for under Benchmark
Planning Case Assessment conditions that the System is expected to experience when the known outage(s) are planned. This assessment shall
include, at a minimum known outages expected to produce more severe System impacts on the Planning Coordinator or Transmission Planner’s portion
of the BES.
CHPD would also like to note, that we support and agree with WPP’s submitted comments.
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Jennie Wike, N/A, Wike Jennie
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Response
Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer
Document Name

2023-07_Unofficial_Comment_Form Draft 2_071624_LIPA comments_08-15-2024 (002).pdf

Comment
Comment on the Implementation Plan:
From the Implementation Plan (IP), the graphic on page 3 of the IP does not match the text on page 2.

In the graphic, it appears that the timeline is based on governmental authority approval, and not on when TPL-008-1 goes into effect.
Page 2 of the IP states:
Phased-In Compliance Dates
Compliance Date for TPL-008-1 Requirement R1
Entities shall be required to comply with Requirement R1 upon the effective date of Reliability Standard TPL-008-1.
Compliance Date for TPL-008-1 Requirements R2, R3, R4, R5, R6
Entities shall not be required to comply with Requirements R2, R3, R4, R5, and R6 until thirty-six (36) months after the effective date of Reliability
Standard TPL-008-1.
Compliance Date for TPL-008-1 Requirements R7, R8, R9, R10, R11
Entities shall not be required to comply with Requirements R7, R8, R9, R10, R11 until sixty (60) months after the effective date of Reliability
Standard TPL-008-1.
To match the text on page 2, our interpretation is that the graphic on page 3 should be MODIFIED as shown on on page 7 of 7 of the
UPLOADED / ATTACHED file named "2023-07_Unofficial_Comment_Form Draft 2_071624_LIPA comments_08-15-2024 (002).pdf".

Comment on Requirement #11
Requirement #11 states:
“Each responsible entity, as identified in Requirement R1, shall provide its Extreme Temperature Assessment results within 60 calendar days of a
request to any functional entity that has a reliability related need and submits a written request for the information.”
This could be interpreted in different ways.
We would recommend the SDT consider modifying the wording (see TPL-001-5.1 Req #8 for reference) and timeframe to be more consistent with TPL001-5.1 Req #, 8 as follows:
“Each responsible entity, as identified in Requirement R1, shall provide its latest completed Extreme Temperature Assessment results within 90
calendar days of a request to any functional entity that has a reliability related need and submits a written request for the information.”
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Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer
Document Name
Comment
Please correct the wording “min” to “max” in the table heading on page-4 of the “Extreme Heat and Cold Weather Benchmark Events Example”
document.

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Ronald Hoover - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
BPA recommends adding "or to its designee" to all references of "ERO" in R2. BPA believes this will add flexibility to the requirement for scenarios such
as large geographical footprints, where benchmark temperatures could be extremely variable"

BPA currently has the following concerns:
R2 - Uncertainty about the events in the NERC library and the process.
R3/R4 - Need a clearly defined scope regarding coordination with the other entities.
R9 Corrective Action Plans, use of Operating Plans could be a cost effective alternative to a CAP and result in acceptable system performance.
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Fon Hiew - NB Power Corporation - New Brunswick Power Transmission Corporation - 5
Answer
Document Name
Comment
Facility Owners (FOs) have an important role in developing and implement corrective action plans. The document does not acknowledge the role of the
FO explicitly. The FO ultimately has the accountability to present CAP and associated investments and cost to its regulatory body for retail service. We
suggest the standard make this explicitly clear.

In certain jurisdiction, extreme temperature ratings have been established, but that is not necessarily the case in all jurisdictions. Will facility owners be
required to establish extreme cold or warm temperature ratings for this standard?

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Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
Modify R11 to match TPL-001-5.1 R8 except change 90 calendar-days to “180 calendar-days” in R8.1 due to the five-year time period between studies.
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Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Document Name
Comment
None.
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Zahid Qayyum - New York Power Authority - 5
Answer
Document Name
Comment
• It’s unclear whether the responsible entity will do an annual reconciliation of cases using actual recorded data? NYPA appreciates if the SDT can
provide clarity on this
• Table 1 in the requirement language should be replaced with Table 1.1, table 1.2 appropriately.
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Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Document Name
Comment
Footnote 1 from Table 1.3 is not reflected in Table 1.1 (it should be up by 'Fault Type' column header).
ETA Definition and Purpose: MRO NSRF notes that the definition for Extreme Temperature Assessment uses BES and the purpose of TPL-001-8
uses BPS. The two should align and MRO NSRF supports the use of “BES” to align with existing standard, TPL-001-5.1. Alternatively, the SDT needs
to justify the reason for the difference.
DRAFT ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance
The process document says,” Refer to the NERC Glossary of Terms for the below capitalized terms used in this process.” While NERC may have
defined these terms, those highlighted in yellow (below) are not in the NERC Glossary of Terms.
• Affected Regional Entity (ARE)
• Compliance Enforcement Authority (CEA)
• Coordinated Oversight
• Extreme Temperature Assessment (ETA) – New! In TPL-008-1 standard
• Lead Regional Entity (LRE)
• Multi-Region Registered Entity (MRRE)

Absence of the Benchmark Library
The MRO NSRF has concerns with finalizing the TPL-008 standard with the benchmark event library unseen as this may have significant impact as to
how the standard should be structured and how it is interpreted and applied.
Relevance to Canada
The MRO NSRF requests that Canadian provinces be considered within the ERO benchmark library.
MRO NSRF requests clarification regarding the following. Is an entity required to use the same benchmark event across its entire footprint or can an
entity use different events for different areas of its footprint? For example, if an MRO NSRF member selects a benchmark event that has high impacts
concentrated in its Southern Region for its first iteration, could the next 5-year iteration use a benchmark event that has high impacts concentrated in its
Central Region?

Depending on how far into the future these requests are made, there may great uncertainty for the resources. Many states have firm policies driving
unit deactivations, but replacement resource location and size is not going to be able to be known. This may lead to these future cases being unsolvable without large reactive or replacement power assumptions.
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Scott Brame, N/A, Brame Scott
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer
Document Name
Comment
Facility Owners (FOs) have an important role in developing and implement corrective action plans. The document does not acknowledge the role of the
FO explicitly. The FO ultimately has the accountability to present CAP and associated investments and cost to its regulatory body for retail service. We
suggest the standard make this explicitly clear.

In certain jurisdiction, extreme temperature ratings have been established, but that is not necessarily the case in all jurisdictions. Will facility owners be
required to establish extreme cold or warm temperature ratings for this standard?
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Daniel Gacek - Exelon - 1
Answer
Document Name
Comment
Overall, Exelon would like to see additional details of events in the benchmark library included in the associated standard requirements. Specifically,
seeking clarity on exactly what data will be included in selected events as well as how event selection will inform coordination.
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Daniela Atanasovski - APS - Arizona Public Service Co. - 1

Answer
Document Name
Comment
None
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Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer
Document Name
Comment
SMUD supports the comments submitted by the MRO NSRF.
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Barbara Marion - Dominion - Dominion Resources, Inc. - 5, Group Name Dominion
Answer
Document Name
Comment
There are concerns over the CAP as well as ambiguity in R2.
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Michael Jones - National Grid USA - 1

Answer
Document Name
Comment
National Grid supports EEI’s comments. In addition, please thoroughly review TPL-008-1 Table 1 to ensure consistency with TPL-001-5.1 Table 1,
where applicable, to ensure nothing has been unintentionally missed. For example and consideration:
Table 1 - General comments:
Footnote 1 (in TPL-001) in header of Event column is ‘missing,’ i.e., not included in TPL-008.
Footnote 1 (in TPL-008), which is Footnote 2 (in TPL-001), is missing(?) from the header of Table 1
Footnote 2 (in TPL-001) in header of BES Level column is ‘missing,’ i.e., not included in TPL-008, while Facility voltage level of Contingency is listed in
new Footnote 2 (in TPL-008) it is still ‘inconsistent.’
Footnote 5 (in TPL-001) related to transformers is ‘missing,’ i.e., not included in TPL-008.
Footnote 9 (in TPL-001) for interruption of firm transmission is ‘missing,’ i.e., not included in TPL-008.
Footnote 11 (in TPL-001) related to DCTs is ‘missing,’ i.e., not included in TPL-008.
Footnote 12 (in TPL-001) on non-consequential load loss is ‘missing,’ i.e., not included in TPL-008.
Table 1.2 – Performance Requirements
P0: “The System shall remain stable” is only listed for P0– Suggest removing since not ‘defined.’ Similar to EEI comment, but recommending deleting
since reference to ‘remain stable’ is unclear.
Allowance for non-Consequential Load Loss as an interim solution seems more stringent than TPL-001.
Requirement to “Simulate the removal of all elements that Protection Systems and other controls are expected to automatically disconnect for each
event” (TPL-001) has no matching counterpart in Table 1.
Event to “Simulate Normal Clearing unless otherwise specified” (TPL-001) has no counterpart in Table 1.
Minor issues: Table 1.2 (in TPL-008) is structured differently than in TPL-001 and placed after the ‘main’ Table 1., The ordering of Non-Consequential
Load Loss and Interruption of Firm Transmission reversed (vs. TPL-001).
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Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Document Name
Comment

Evergy supports and incorporates by reference the comments of the Midwest Reliability Organization's NERC Standards Review Forum (MRO NSRF)
on question 9
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Amy Wilke - American Transmission Company, LLC - 1
Answer
Document Name
Comment
ATC supports the MRO NSRF comments.
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Junji Yamaguchi - Hydro-Quebec (HQ) - 5
Answer
Document Name
Comment
1.
Facility Owners (FOs) have an important role in developing and implement corrective action plans. The document does not acknowledge the role
of the FO explicitly. The FO ultimately has the accountability to present CAP and associated investments and cost to its regulatory body for retail
service. We suggest the standard make this explicitly clear.

2.
In certain jurisdiction, extreme temperature ratings have been established, but that is not necessarily the case in all jurisdictions. Will facility
owners be required to establish extreme cold or warm temperature ratings for this standard?
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company

Answer
Document Name
Comment
•

•
•

Key responsibilities and deadline details from the “ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and
Maintenance” should be included in the TPL-008-1 reliability standard to define the ERO’s responsibilities as they pertain to the development
and maintenance of the Weather Event Library. At minimum, the suggested language and footnote proposed by EEI in response to survey
question 2 should be included.
Page 3, A.3, the Introduction Purpose should change “Bulk Power System (BPS)” to “Bulk Electric System (BES)” for consistency.
Reference to the benchmark events as either ‘temperature benchmark events’ or ‘benchmark temperature events’ should be made consistent
throughout the document. Slight preference for ‘temperature benchmark events’.

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Helen Lainis - Independent Electricity System Operator - 2
Answer
Document Name
Comment
We support NPCC TFCP comment regarding whether facility owners will be required to establish extreme cold or warm temperature ratings
for this standard?

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Devin Shines - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
The DT should consider whether the use of “The responsible entity” is appropriate instead of “Each responsible entity”. Use of “each” seems to read that
the PC and all TPs must each do the requirements, whereas the intention is that the PC and TPs decide who is going to be the responsible entity for
each step.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE has identified two issues with the proposed Implementation Plan. First, the Implementation Plan timeline and narrative do not consistently
use the same start date for all applicable compliance dates. In particular, the compliance dates for Requirement R1 appear tied to the Standard
Effective Date, but the compliance dates in the proposed timeline appear tied to the date of the government order. Second, Texas RE notes that no
initial performance date is specified for Requirement R8.

Phased Implementation Dates
Texas RE requests again that the implementation plan descriptions and diagram be aligned to a consistent start date for all applicable
requirements. Texas RE notes that in the narrative description, compliance activities appear to be linked to the Standard Effective Date, which is 12
months following the first calendar quarter after the order of the applicable governing authority approving the standard. For instance, the proposed
Implementation Plan provides that entities shall be required to comply with Requirement R1 upon the effective date of the Reliability Standard TPL-0081. Similarly, compliance dates for Requirements R2 through R6 are occur 36 months after the effective date of standard.

The table then provides that the enforcement date for Requirement R1 is 12 months following the applicable governing authority’s order – that is, the
Effective Date of the Standard. In contrast, however, the implementation timeline then appears to link the various staggered implementation dates for
R2 through R6 and R7 through R11 to the date of the order approving the standard, not the Effective Date of the Standard itself. That is, entities in
effect have only 24 months from the Effective Date of the Standard to comply with R2 though R6 under the timeline, not 36 months from the Effective
Date of Reliability Standard TPL-008-1 as set forth in the Implementation Plan narrative.

Texas RE recommends that the SDT either revise the timeline chart to consistently link all required compliance dates to the Effective Date of the
Standard or, alternatively, revise the narrative description to reference the date of the order approving the standard for all required compliance dates to
avoid confusion.

The following table summarizes the Implementation Plan and chart as currently drafted:

Phased In Compliance Dates
Effective Date of the Standard = The first day of the first calendar quarter that is twelve (12) months after the effective date of the applicable governing
authority’s order.
R1 = Effective Date of TPL-008-1 (12 months after the government order)

R2, R3, R4, R5, R6 = Effective Date + 36 months
R7, R8, R9, R10, R11 = Effective Date + 60 months

The diagram in the implementation plan shows the following:
R1 = Effective Date of TPL-008-1 (12 months after the government order date)
R2, R3, R4, R5, R6 = Effective Date for TPL-008-1 + 24 months (36 months after the government order date)
R7, R8, R9, R10, R11 = Effective Date for TPL-008-1 + 48 months (60 months after the government order date)

Initial Performance Date
Additionally, Requirement R8 states that the Extreme Temperature Assessment shall be done once every five calendar years. Since there is no initial
performance date specified, Texas RE understands that the entity would not need to perform its initial Extreme Temperature Assessment until 5 years
after the effective date of Requirement R8 (that is, 10 years after the Effective Date of Requirement R8). Texas RE generally recommends establishing
an explicit initial performance date upon the effective date of the requirement to avoid delaying compliance obligations an additional five years.
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Israel Perez - Israel Perez On Behalf of: Laura Somak, Salt River Project, 3, 6, 5, 1; Mathew Weber, Salt River Project, 3, 6, 5, 1; Thomas
Johnson, Salt River Project, 3, 6, 5, 1; Timothy Singh, Salt River Project, 3, 6, 5, 1; - Israel Perez
Answer
Document Name
Comment
The standard as written is inconsistent in all references to the attached tables. "Table 1" should be removed from the requirement language and table
1.1 and 1.2 used appropriately.
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Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer
Document Name

Comment
Ameren supports EEI's comments on this project.
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Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Document Name
Comment
Purpose statement includes use of BPS but new definition is limited to BES. Was that intentional? R11-Who determines “reliability related need”?
There are no defined actions to address deficiencies recognized by an Extreme Temperature Assessment. Only CAPs are called out, is that the
expectation?
Extreme weather may not cover all of a responsible entity’s area. Is it the DT’s assumption that it would and therefore no partial footprint Extreme
Temperature Assessments would meet the Requirements? Or are partial footprint Extreme Temperature Assessments allowable? Based on the
additional materials provided it appears that boundaries have been set.
Table Issues- Where is Footnote 1 within the Table used?
Steady State P1- Capitalize “Facility ratings”
Requirement R5 Severe VSL should say “completing” not “performing”.
Requirement R7 VSLs need rewritten to match language of the Standard unless language gets changed back to “Contingencies”.
Requirement R8 VSLs indicate completion of an Extreme Temperature Assessment but do not reflect completion of “steady state and transient stability
analyses”. If one of those is not done, effectively an Extreme Temperature Assessment has not been performed. Is that correct?
Benchmark Weather Event Development and Maintenance Document
There are several terms noted as being in the Glossary of Terms but are not used in the process nor are they in the Glossary. Many deal with the
Coordinated Oversight Program that has its own set of definitions. The sample benchmark event materials for the Weather Event Library provide some
clarity on what materials will be included. Still looks like additional information may be needed for registered entities approach in using the events in the
Extreme Temperature Assessments.

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Teresa Krabe - Lower Colorado River Authority - 5
Answer
Document Name
Comment
The Technical Rationale for R7 mentions that the benchmark planning cases will factor generation and transmission outages. LCRA does not believe
its clear on how the benchmark cases will account for generation and transmission outages prior to running the specified contingencies and how
outages factor into CAP development.
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Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer
Document Name
Comment
Minnesota Power supports MRO’s NERC Standards Review Forum’s (NSRF) comments.
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Matt Lewis - Lower Colorado River Authority - 1
Answer
Document Name
Comment
The Technical Rationale for R7 mentions that the benchmark planning cases will factor generation and transmission outages. LCRA TSC does not
believe its clear on how the benchmark cases will account for generation and transmission outages prior to running the specified contingencies and how
outages factor into CAP development.

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Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Document Name
Comment
Tri-State supports the comments submitted by the MRO NSRF referencing the absence of the Benchmark Library.
"MRO NSRF has concerns with finalizing the TPL-008 standard with the benchmark event library unseen as this may have significant impact as to how
the standard should be structured and how it is interpreted and applied."
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Romel Aquino - Edison International - Southern California Edison Company - 3
Answer
Document Name

Near Final EEI Comments P2023-07_ TPL-008 Draft 2 _ Rev. 0g 8_21_2024.docx

Comment
See comments submitted by the Edison Electric Institute, attached.
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Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer
Document Name
Comment
SPP recommends that the drafting team coordinate with other drafting teams like the Energy Reliability Assessment (ERA) to ensure that these
assessments doesn’t create overlap for each other’s processes and efforts.
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Kinte Whitehead - Exelon - 3
Answer
Document Name
Comment
Overall, Exelon would like to see additional details of events in the benchmark library included in the associated standard requirements. Specifically,
seeking clarity on exactly what data will be included in selected events as well as how event selection will inform coordination.
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Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer
Document Name
Comment
•

In general, the development of an extreme weather benchmark event is reasonable. The difficulty in properly assessing this draft Reliability
Standard is the unknowns around the benchmark events. Whether these events are solely temperature-based or if there is a related electrical
system or resource availability embedded needs to be clarified in the standard language. Also, there are numerous inconsistencies,
ambiguities, and significant burdens being placed on the PC/TP in this standard that will result in problematic assessments, issues with
coordination, competing CAPS within Interconnections, and cost for more staff to support the significant burden this standard poses.

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Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments:

Facility Owners (FOs) have an important role in developing and implement corrective action plans. The document does not acknowledge the role of the
FO explicitly. The FO ultimately has the accountability to present CAP and associated investments and cost to its regulatory body for retail service. We
suggest the standard make this explicitly clear.
In certain jurisdiction, extreme temperature ratings have been established, but that is not necessarily the case in all jurisdictions. Will facility owners be
required to establish extreme cold or warm temperature ratings for this standard?
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Keith Jonassen - Keith Jonassen On Behalf of: John Pearson, ISO New England, Inc., 2; - Keith Jonassen
Answer
Document Name
Comment
While ISO-NE appreciates the Benchmark Event Example, many concerns that the industry has regarding this standard and the studies that would be
required, could be alleviated by the SDT/NERC providing a list of the Benchmark Temperature Events that would be available to choose from. It is
difficult for areas to determine what would be required and to agree to perform studies on specific events without the list of events to choose from for the
studies.
In the specific Benchmark Event Example, ISO-NE did not experience a cold weather event so there is no value to ISO-NE in studying that particular
event.
ISO-NE requests that a list of Benchmark Events and applicable parameters be provided prior to any final Ballot on the TPL-008 Standard.
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Ben Hammer - Western Area Power Administration - 1
Answer
Document Name
Comment
Absence of the Benchmark Library
WAPA has concerns with finalizing the TPL-008 standard with the benchmark event library unseen as this may have significant impact as to how the
standard should be structured and how it is interpreted and applied.
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Michael Goggin - Grid Strategies LLC - 5
Answer
Document Name
Comment
First, to comply with FERC Order 896, the standard should specify that benchmark events and Extreme Temperature Assessments will account for
concurrent/correlated outages of generators during extreme heat and cold events. In Order 896 paragraph 88, FERC directs “NERC to require under
the new or revised Reliability Standard the study of concurrent/correlated generator and transmission outages due to extreme heat and cold events in
benchmark events,” explaining in paragraph 89 that “it is necessary that responsible entities evaluate the risk of correlated or concurrent outages and
derates of all types of generation resources and transmission facilities as a result of extreme heat and cold events.”
The drafts of TPL-008 and the associated “Consideration of FERC Order 896 Directives” document appear to put the burden on responsible entities and
not NERC for accounting for correlated outages: “This directive is addressed in proposed TPL-008-1 through Requirement R3 Part 3.2. The responsible
entity is obligated to modify the benchmark planning cases to include seasonal and temperature dependent adjustment for Load, generation,
Transmission, and transfers which represent the selected benchmark events.”[1]
Having responsible entities and not NERC conduct this adjustment increases the risk that different regions will use inconsistent methods for doing so,
and at worst responsible entities that want to avoid addressing reliability concerns through a Corrective Action Plan will use unrealistically low
assumptions for the rate of correlated generator outages or other input assumptions like load and transfers. This assumption can have such a large
impact on results it cannot be left to responsible entities, and should be made by NERC. The drafting team’s Technical Rationale used similar logic in
deciding that NERC (the Electric Reliability Organization or ERO) should assemble the benchmark planning cases: “to ensure consistency across
regions, it is necessary for the ERO to have the responsibility for determining the suitability of benchmark events to represent probable future
conditions.”
Given the significant variation in the rates at which different fuel types experience correlated outages,[2] and rapid changes in the generation mix that
may cause the future power system to have greater or lesser exposure to correlated outage risk, it is particularly important for the benchmark events
and Extreme Temperature Assessments to account for the concurrent/correlated outage risk of each fuel type in the future generation mix. In recent
cold snap events, gas generator outages due to equipment failures and fuel supply interruptions have accounted for the majority of outages. NERC
GADS data can be used to assess the rate of correlated outages and derates of generators by fuel type.{C}[3]
Second, the benchmark cases and Extreme Temperature Assessments should account for changes to generation, demand, and transmission resulting
from climate change, electrification of heating, and other factors that are affecting the risk posed by extreme heat and cold. Accounting for how climate
change is increasing the frequency and magnitude of extreme heat and cold events is consistent with FERC’s Order 896 directive in paragraph 40: “We
also direct NERC to ensure the reliability standard contains appropriate mechanisms for ensuring the benchmark event reflects up-to-date
meteorological data. The increasing intensity, frequency, and unpredictability of extreme weather conditions requires that key aspects of the benchmark
events be reviewed, and if necessary, updated periodically to ensure the corresponding benchmark planning cases reflect updated meteorological
data.” Electrification of heating is also increasing the sensitivity of electricity demand to extreme cold conditions, which should be accounted for in the
benchmark cases and Extreme Temperature Assessments.
Third, due to the impact of climate change, electrification, and rapid changes in the generation mix, requirement R8 should require responsible entities
to complete an Extreme Temperature Assessment more frequently than at least once every five calendar years. As noted above, FERC Order 896
specifies that the meteorology underlying benchmark cases should be updated at least every five years, but the generation mix and other grid
conditions can change more rapidly than that. TPL-001 requirement R2 requires Planning Assessments to be conducted annually, and a similar annual
requirement for Extreme Temperature Assessments is appropriate given that extreme heat and cold events are the largest threat to electric reliability.

Finally, the requirement in Section 4.1 under R4 is unclear and may be inadequate. That section states that the Extreme Temperature Assessment shall
evaluate “one of the years in the Long-Term Transmission Planning Horizon. The rationale for the year selected for evaluation shall be available as
supporting information.” At minimum, that section of R4 should be modified to provide responsible entities with greater direction on which year or years
to assess. Because extreme heat and cold risks can evolve over time due to changes in the generation mix, load, and the impact of climate change, R4
should require the responsible entity to document that the year selected is likely to pose the greatest reliability risk. If it cannot be determined which year
is likely to pose the greatest risk, then the responsible entity should be required to conduct the assessment for all years that may pose the greatest risk.
This is important because of the long and ambiguous timeframe covered by the Long-Term Transmission Planning Horizon, which the NERC Glossary
indicates is the “Transmission planning period that covers years six through ten or beyond when required to accommodate any known longer lead time
projects that may take longer than ten years to complete.” Planning for multiple years is consistent with the requirement in Section 2.1.1. of requirement
R2 for TPL-001, which requires Planning Assessments to examine multiple years by incorporating “System peak Load for either Year One or year two,
and for year five.”[4]
Requirement R9
a. Requirement R9 should be modified to specify that the expected impact of extreme heat and cold should be accounted for when designing and
measuring the impact of the solutions proposed in a Corrective Action Plan (CAP). Many potential solutions in a CAP can have greater or lesser impact
under extreme heat or cold conditions. For example, a CAP that relies on adding gas generation can be less effective under extreme heat due to output
reductions due to ambient temperature derates, and under extreme cold due to correlated gas generator outages. Gas generator outages due to
equipment failures and fuel supply interruptions have accounted for the majority of outages during recent cold snap events.{C}[5] As noted above in
response to question 4, FERC’s directive in paragraph 89 of Order 896 states that “it is necessary that responsible entities evaluate the risk of
correlated or concurrent outages and derates of all types of generation resources and transmission facilities as a result of extreme heat and cold
events.” On the other hand, CAPs that include demand response and energy efficiency programs related to building HVAC systems can offer
contributions that are larger than expected during extreme heat or cold because load associated with cooling or heating is higher during such events.
During extreme cold events, expanded transmission ties with neighboring grid operators can also exceed the benefits they offer under normal conditions
because transmission line thermal limits are higher during extreme cold and wind chill conditions. Transmission ties also tend to offer large benefits
during extreme heat and cold, as severe weather events tend to be at their most extreme in geographically confined areas, ensuring at least some
nearby grid operators are not experiencing shortfalls in generation.[6] The benefits of interregional transmission are even greater at higher renewable
penetrations.[7] The value of transmission ties during extreme heat and cold events should be accounted for when assessing baseline performance
during benchmark events as well as quantifying the value of expanding these ties as part of a CAP.
The higher transfer capacity of advanced conductors under extreme heat and cold conditions should also be accounted for, as carbon and composite
core conductors sag roughly half as much as comparable ACSR conductors. Finally, Grid-Enhancing Technologies like dynamic line ratings, topology
optimization, and power flow control devices offer significant benefits when the grid may be congested due to extreme temperatures. Dynamic line
ratings are particularly valuable for enabling operators to safely use transmission lines’ higher thermal limits during extreme cold and wind chill
conditions.
Accounting for how a CAP will fare under the extreme heat or cold conditions it is designed to solve is essential for ensuring reliability. Without
accounting for the reduced effectiveness of some CAP elements under extreme heat or cold, planners will be blind to potential reliability risks. In other
cases, failing to account for the effectiveness of specific CAP measures under extreme heat or cold will result in a suboptimal selection of solutions.
Extreme heat and cold must not only be accounted for in identifying reliability risks, but also designing solutions to those risks.
b. The draft of R9 also includes a potential loophole that a responsible entity could use to avoid implementing a CAP that is needed to address reliability
concerns.
First, allowing load curtailment for a P1 contingency under TPL-008 is a major departure from the requirements of TPL-001, which do not allow load
shedding for a P1 contingency.{C}[8] Allowing responsible entities plans’ to include load shed when they experience a single P1 contingency under
extreme heat or cold conditions is contrary to FERC’s intent in Order 896 that NERC enact a standard that will ensure reliable operations under extreme
heat and cold conditions.
More generally, a major concern with the draft standard is that there is no compliance mechanism to ensure CAPs are implemented. If implementing
some CAP solutions requires action by an entity other than the transmission planner or planning coordinator responsible entities, the draft standard
should be revised to include such a requirement on those entities. Other draft NERC standards include requirements to implement CAPs, and similar

language could be adopted for TPL-008. For example, requirement R9 of the PRC-028 draft requires a generator or transmission owner to “develop,
maintain, and implement a Corrective Action Plan to provide the required capability,”{C}[9] and requirement R6 of the PRC-030 draft requires “Each
applicable Generator Owner shall, for each of its CAPs developed pursuant to Requirement R5:
6.1. Implement the CAP;
6.2. Update the CAP if actions or timetables change; and
6.3. Notify each applicable Reliability Coordinator if CAP actions or timetables change and when the CAP is completed.”[10]{C}
Implementation plan
The draft Implementation Plan proposes that requirements R7-R11, which require the Extreme Temperature Assessment and any resulting Corrective
Action Plan, do not take effect until more than 6 years after the Standard is approved by FERC. This unnecessary delay is contrary to FERC’s directive
in Order 896 and the urgent importance of planning for extreme heat and cold events.
NERC’s 2023 State of Reliability Overview concluded that “extreme weather events continue to pose the greatest risk to reliability due to the increase in
frequency, footprint, duration, and severity.” FERC Order 896 was also clear that the increasing frequency and magnitude of extreme weather events
“have created an urgency to address the negative impact of extreme weather on the reliability of the Bulk-Power System” (at paragraphs 21-22).
Waiting until after 2030 to address the largest threat to grid reliability does not make sense. Such a delay is also unnecessary, as entities responsible
for TPL-008 already conduct nearly all of the elements of TPL-008 today to comply with TPL-001. TPL-008 effectively requires running similar analyses
as TPL-001, but for extreme heat and cold scenarios. As a result, it should be straightforward for responsible entities to modify their existing planning
practices to incorporate the two additional scenarios.
This unnecessary delay is also at odds with FERC’s directive in Order 896. At paragraph 188, FERC directed “NERC to propose an implementation
timeline for the new or modified Reliability Standard, with implementation beginning no later than 12 months after the effective date of a Commission
order approving the proposed Reliability Standard.” Under the draft Implementation Plan, the only requirement of TPL-008 that comes close to falling
within the 12-month timeline FERC directed is compliance with R1, which begins “the first day of the first calendar quarter that is twelve (12) months
after the effective date of the applicable governmental authority’s order approving the standard.”
More importantly, R1 only requires that “Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall determine and identify each
entity’s individual and joint responsibilities for performing the studies needed to complete the Extreme Temperature Assessment,” and as such is a
minor procedural step towards implementing the actual Extreme Temperature Assessment and any resulting Corrective Action Plan in R7-R11. As
noted above, those meaningful requirements do not begin until more than 6 years after the standard is approved by FERC. To comply with FERC’s
directive, the drafting team should require compliance with R7-R11 to begin within 12 months of FERC approval of the standard, and the interim steps in
R2-R6 should also be moved up from the Implementation Plan’s proposed deadline of 36 months after the effective date of the standard.

{C}[1]{C} NERC, Consideration of FERC Order 896 Directives (March 2024),
https://www.nerc.com/pa/Stand/Project202307ModtoTPL00151TransSystPlanPerfReqExWe/202307_Consideration%20of%20FERC%20Order%20896%20Directives%20Final_032024.pdf, at 5
{C}[2]{C} See, e.g., FERC and NERC, Winter Storm Elliott Report: Inquiry into Bulk-Power System Operations During December 2022 (October 2023),
https://www.ferc.gov/media/winter-storm-elliott-report-inquiry-bulk-power-system-operations-during-december-2022, at 17; FERC and NERC, The
February 2021 Cold Weather Outages in Texas and the South Central United States (November 2021), https://www.ferc.gov/media/february-2021-coldweather-outages-texas-and-south-central-united-states-ferc-nerc-and, at 16; FERC and NERC, 2019 FERC and NERC Staff Report: The South Central
United States Cold Weather Bulk Electric System Event of January 17, 2018 (July 2019), https://www.ferc.gov/legal/staff-reports/2019/07-18-19-fercnerc-report.pdf; PJM, Analysis of Operational Events and Market Impacts During the January 2014 Cold Weather Events (May 2014),
https://www.pjm.com/~/media/library/reports-notices/weather-related/20140509-analysis-of-operational-events-and-market-impacts-during-the-jan-2014cold-weather-events.ashx.

{C}[3]{C} For example, see the analysis of GADS data provided in S. Murphy et al., Resource adequacy risks to the bulk power system in North America
(February 2018), https://www.sciencedirect.com/science/article/pii/S0306261917318202, with Supplementary Material including outage data available at
https://ars.els-cdn.com/content/image/1-s2.0-S0306261917318202-mmc1.zip
{C}[4]{C} https://www.nerc.com/pa/Stand/Reliability%20Standards/TPL-001-4.pdf
{C}[5]{C} See, e.g., FERC and NERC, Winter Storm Elliott Report: Inquiry into Bulk-Power System Operations During December 2022 (October 2023),
https://www.ferc.gov/media/winter-storm-elliott-report-inquiry-bulk-power-system-operations-during-december-2022, at 17; FERC and NERC, The
February 2021 Cold Weather Outages in Texas and the South Central United States (November 2021), https://www.ferc.gov/media/february-2021-coldweather-outages-texas-and-south-central-united-states-ferc-nerc-and, at 16; FERC and NERC, 2019 FERC and NERC Staff Report: The South Central
United States Cold Weather Bulk Electric System Event of January 17, 2018 (July 2019), https://www.ferc.gov/legal/staff-reports/2019/07-18-19-fercnerc-report.pdf; PJM, Analysis of Operational Events and Market Impacts During the January 2014 Cold Weather Events (May 2014),
https://www.pjm.com/~/media/library/reports-notices/weather-related/20140509-analysis-of-operational-events-and-market-impacts-during-the-jan-2014cold-weather-events.ashx.
{C}[6]{C} https://acore.org/wp-content/uploads/2021/07/GS_Resilient-Transmission_proof.pdf
{C}[7]{C} https://www.nrel.gov/docs/fy22osti/78394.pdf
{C}[8]{C} https://www.nerc.com/pa/Stand/Reliability%20Standards/TPL-001-5.pdf, at 21
{C}[9]{C} https://www.nerc.com/pa/Stand/Project202104ModificationstoPRC0022DL/2021-04_AB_PRC-028-1_Clean_03182024.pdf
{C}[10]{C} https://www.nerc.com/pa/Stand/Project202302PerformanceofIBRsDL/2023-02%20PRC-030-1_032524.pdf
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Response
Bobbi Welch - Midcontinent ISO, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee (SRC) Project 2023-07 TPL-008-1 Draft #2
Answer
Document Name

2023-07_Unofficial_Comment_Form_Draft 2_SRC_08-22-24_final.docx

Comment
DRAFT ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance
The process document says,” Refer to the NERC Glossary of Terms for the below capitalized terms used in this process.” While NERC may have
defined these terms, the following terms are not currently in the NERC Glossary of Terms.
• Affected Regional Entity (ARE)
• Compliance Enforcement Authority (CEA)
• Coordinated Oversight
• Extreme Temperature Assessment (ETA)
• Lead Regional Entity (LRE)

• Multi-Region Registered Entity (MRRE)
Relevance to Canada
The SRC requests that Canadian provinces be considered within the ERO benchmark library.
Need for regional application of benchmark events for PCs covering large areas
SRC requests clarification regarding the following. Is an entity required to use the same benchmark event across its entire footprint or can an entity use
different events for different areas of its footprint? For example, if an SRC member selects a benchmark event that has high impacts concentrated in its
Southern Region for its first iteration, could the next 5-year iteration use a benchmark event that has high impacts concentrated in that member’s
Central Region?
Resource uncertainty in the Planning Horizon may lead to unsolvable study cases.
Depending on how far into the future these Extreme Temperature Assessments are performed, there may be great uncertainty as to the resources
available. Many states have firm policies driving unit deactivations, but replacement resource location and size may be unknown. This may lead to
future cases being un-solvable without large reactive or replacement power assumptions. Furthermore, the farther out in the future an extreme case is
studied, the greater the corresponding uncertainties in resource availability due to extreme weather conditions become; study requirements on this topic
are only now being considered under the Project 2024-02 Energy Assurance Planning Horizon SAR.
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Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
Document Name
Comment
A benchmark library maintained by the ERO is a welcome reference for transmission entities, however, local climate and geographic-specific extreme
weather conditions should be made at Planning Coordinator and Transmission Planner level.
Extreme Heat/Cold conditions are already sensitivity scenarios to the normal long-term planning scenarios. Adding sensitivity cases on top of these
“sensitivity scenarios” is redundant and unnecessarily burdensome to transmission entities.
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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name

Comment
ERCOT joins the comments submitted by the IRC SRC and adopts them as its own.
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Elizabeth Davis - Elizabeth Davis On Behalf of: Thomas Foster, PJM Interconnection, L.L.C., 2; - Elizabeth Davis
Answer
Document Name

TPL-008-1 Process Flow.pdf

Comment
PJM supports the IRC SRC comments and adds a process flow (attached) to assist in document organization and structure that are very important to
ease of use and clarity.
PJM wants to thank NERC and the Project Team for all their hard work and consideration of the IRC SRC and PJM submitted comments.

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John Brewer - National Energy Technology Laboratory - 9 - NA - Not Applicable
Answer
Document Name
Comment
A more inclusive process for review and approval of benchmark temperature events should be developed. Currently, only events submitted by an entity
will go through the more inclusive review process by review panel.
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Comments submitted by Long Island Power Authority

Submitter’s Name
Answer

Y/N

Document Name

(if an attachment is provided by submitter)

Comment
Submitter’s comments
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# of other submitters who agree with these comments
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# of other submitters who disagree with these comments

Response
(Drafting team’s response to submitter’s comments)
Submitter’s Name
Answer

Y/N

Document Name

(if an attachment to comments is provided by submitter)

Comment
Submitter’s comments
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0

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# of other submitters who agree with these comments
0

# of other submitters who disagree with these comments

Response
(Drafting team’s response to submitter’s comments)
Submitter’s Name (group info also provided)
Answer

Y/N

Document Name

(if an attachment to comments is provided by submitter)

Comment
Submitter’s comments
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# of other submitters who disagree with these comments

(Drafting team’s response to submitter’s comments)

Summary Response to TPL-008-1 Draft 2
Comments Received

NERC Project 2023-07 Transmission Planning Performance Requirements
for Extreme Weather | October 2024
Comments Received Summary

There were 74 sets of responses, including comments from approximately 191 different people from
approximately 118 companies representing 10 of the Industry Segments. A summary of comments
submitted can be reviewed on the project page.
If you have an interest in joining the distribution list for this project, please reach out to Senior Standards
Developer, Jordan Mallory.
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 Manager of Standards Jamie Calderon (via email) or at (404) 960-0568.

Consideration of Comments

The NERC Project 2023-07 thanks all of industry for your time and comments. The drafting team (DT) feels
that many great points have been provided for the DT to consider during the drafting phase of this project.
High level themes received from industry are located below (bolded is the high-level theme followed by the
DT’s response).

Benchmark Events

Many commenters expressed concern that they cannot fully approve the Extreme Temperature Assessment
definition and TPL-008-1 Standard without having benchmark events information. In addition, some entities
expressed concern about having to agree to a requirement that has yet to be fully developed. Based on the
technical rationale, there is an expectation that the ERO will determine suitability and make available
benchmark events representative of future information. Once the initial library of events has been
developed, entities would be in a better position to consider support for this requirement.
Drafting team response:
NERC is still committed to providing additional information regarding the criteria used in the development
of this initial population of the benchmark event library, the process for maintaining the library, the process
for entity submitted benchmark events and the criteria for which they will be evaluated for approval, as
well as the future state envisioned for ongoing curation of the library with industry involvement and climate
data subject matter experts.

RELIABILITY | RESILIENCE | SECURITY

To best assist the team when voting “No,” please provide comments specific to the Standard and
requirements that is within scope for the team to address. As NERC is directed by FERC to create the
benchmark event library, it is unclear what further improvements can be made to the TPL-008-1 Standard
by the DT.

Definitions

A commenter recommended that the DT should consider making the definition of Extreme Temperature
Assessment align better with the definition of Planning Assessment.
Drafting team response:
The DT originally had the proposed Extreme Temperature Assessment definition aligned with the definition
of Planning Assessment. However, to align with the intent of TPL-008-1, the DT included language to
specifically focus on extreme heat and extreme cold temperature events. In addition, the DT also removed
Corrective Action Plans (CAPs) from the definition because not all CAPs are required for considered
Contingencies. Specifically, CAPs are only required when the analysis of a benchmark planning case
indicates the responsible entity’s portion of the Bulk Electric System is unable to meet performance
requirements for TPL-008-1 Table 1 P0 or P1 Contingencies, while possible actions are required in the
benchmark planning cases for Table 1 P7 Contingencies and in the sensitivity cases for Table 1 P0, P1, and
P7 Contingencies. Therefore, the definition of Planning Assessment in the NERC Glossary of Terms goes
beyond the intent of what is required in TPL-008-1 for Corrective Action Plans.

Requirement R1

Maintaining Models

A commenter recommends that the DT add the term “maintaining models” to the wording for R1 as that is
an important joint responsibility for the Planning Coordinator (PC) and Transmission Planner (TP) to do in
support of the assessment. The modifications in Draft 2 do not address this concern.
Drafting team response:
Requirement R1 is focused on identifying the zone in which the Planning Coordinator belongs and the
individual and joint responsibilities between the Planning Coordinator and its Transmission Planner(s) for
completing the Extreme Temperature Assessment. The completion of the Extreme Temperature
Assessment includes developing models, having criteria, selecting Contingencies for evaluation, completing
steady state and transient stability analyses, developing CAPs in the benchmark planning cases for Table 1
P0 and P1 Contingencies, and documenting possible actions in the benchmark planning cases for Table 1 P7
Contingencies and in the sensitivity cases for Table 1 P0, P1, and P7 Contingencies. Therefore, the DT did
not feel it was necessary to explicitly identify a list of what needs to be discussed and agreed upon by the
Planning Coordinators and Transmission Planners in Requirement R1, as it is identified throughout the TPL008-1 Standard.

Planning Coordinator or Transmission Planner

A commenter recommends that the DT choose either the PC or TP to be responsible for Requirement R1. By
allowing the responsible party to be either the TP or PC, the two parties may not agree on all terms or there
Consideration of Comments | Draft 2 Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
October 2024

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may result in a reliability gap. Please provide clarification on which responsibilities will belong to the
Planning Coordinator and Transmission Planner.
Drafting team response:
In accordance with Requirement R1, each Planning Coordinator and its Transmission Planner(s) within the
PC’s footprint must coordinate each entity’s individual and joint responsibilities when completing the
Extreme Temperature Assessment. The purpose of this requirement is to have the PC and its TP(s) identify
their individual and joint responsibilities for the following activities: developing models, having criteria,
selecting Contingencies for evaluation, completing steady state and transient stability analyses, developing
CAPs in the benchmark planning cases for Table 1 P0 and P1 Contingencies, documenting possible actions
in the benchmark planning cases for Table 1 P7 Contingencies and in the sensitivity cases for Table 1 P0, P1,
and P7 Contingencies, and providing study results to any functional entity who has a reliability related need.
Based on outreach, the DT did not find it appropriate to be overly prescriptive, given regional differences.
Therefore, leaving it up to the PC and its TP(s) is appropriate and acceptable by the majority of industry. In
general, the Planning Coordinator will lead in its coordination with its Transmission Planner(s) to develop
each entity’s individual and joint responsibilities for completing Extreme Temperature Assessment.

Category P0

A couple of commenters asked if the use of “category P0” to describe normal system condition in R1
appropriate, given that it includes both benchmark and extreme events, which are not typically considered
normal operating conditions.
Drafting team response:
Yes, the use of “Category P0” in the TPL-008-1 Standard specifically refers to benchmark planning cases that
are developed from benchmark events. The developed benchmark planning cases establish Category P0 as
the normal System condition in TPL-008-1 Table 1 before further Contingencies are applied as part of the
assessment.

Requirement R2

Many commenters continued to express concern with the lack of knowing what the benchmark events
are, and what data entities will have to work from when selecting benchmark events.

Regional Entities to Complete Assessments

Some commenters stated that Regional Entities should be the entity to develop the benchmark events.
Drafting team response:
Benchmark events are developed based on historical events, which focus on events that may cover a
larger area than the Regional Entity oversees. The ERO Enterprise, as an entirety, has the bigger picture
and is the appropriate entity to develop benchmark events that could result in reliability issues affecting
multiple regions.

Planning Coordinator Maintain Benchmark Events
Consideration of Comments | Draft 2 Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
October 2024

3

Some commenters expressed that the Planning Coordinator should be able to develop benchmark events
that do not exist within the ERO Benchmark Event library and that entities should be able to maintain the
benchmark event data.
Drafting team response:
FERC Order 896 recognizes that historical events may span across regions and therefore, the ERO is in the
best position to develop benchmark events. However, based on recent conversations, the DT has updated
the TPL-008-1 Standard to allow Planning Coordinators, in coordination with other Planning Coordinators,
to develop benchmark events should the events provided by the ERO not be adequate for Planning
Coordinators to consider. In addition, Requirement R2 has been updated to reflect what is being provided
by the ERO, which addresses the subparts and what would be required from entities should they choose
to develop their own benchmark events in coordination with other PCs. The important note here is that
one common extreme heat benchmark temperature event and one common extreme cold benchmark
temperature event is selected and studied among the PCs within the zone identified in Attachment 1 of
the TPL-008-1 Standard.

Requirement for NERC to Coordinate with PCs

Some commenters expressed that a requirement should be added to the TPL-008-1 standard requiring
NERC to coordinate with Planning Coordinators when developing benchmark events.
Drafting team response:
A NERC Process 1 has been developed and posted to the NERC Project 2023-07 page laying out the process
for the 5-year iteration of benchmark events being developed during the second 38-day comment and
ballot period. Per the process, the ERO will engage with industry subject matter experts during year one
of developing the next round of benchmark events.

Develop an Attachment 1 Like TPL-007

Some commenters expressed that Attachment 1 in TPL-008-1 should reflect TPL-007.
Drafting team response:
TPL-008-1 is different compared to TPL-007. Industry must take into account the FERC directives assigned
to this project. FERC states in FERC Order 896 P58 to “[d]irect NERC to develop benchmark events for
extreme heat and cold weather events through the Reliability Standards development process. We agree
with Indicated Trade Associations that the development of adequate benchmark events is critical and
should be committed to the subject matter experts on the DT. We also agree with Entergy that NERC will
be able to tailor benchmark events to capture regional differences and the different risks that each region
faces during extreme heat and cold weather events. While Regional Entities and reliability coordinators
are encouraged to participate in the NERC Reliability Standards development process to develop the
benchmark events, we disagree with AEP and other commenters who recommend that entities other than
NERC take the lead in the development of benchmark events.” An update made to the TPL-008-1
Standard shows a map of the zones in which PCs are located and has been added as Attachment 1. A
1

Link to NERC Process document: NERC Standards Development Process Document

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process regarding the development and update of benchmark events has been drafted and posted to the
NERC Project 2023-07 project page.

Coordination through MMWG and ERAG

Some commenters believe it is not appropriate to assign the Electric Reliability Organization (ERO)
responsibility within the standard requirement that directly impacts the compliance to the standard
requirement. There is a compliance risk to the directly assigned entity if the ERO fails to uphold its
responsibility to maintain the database. We suggest coordinating this the way MMWG is coordinated
through ERAG in the Eastern Interconnection.
Drafting team response:
A process has been developed for entities to follow regarding the development of the benchmark events
over the 5-year iterations. In year one, the ERO will engage with industry subject matter experts to
develop the next round of benchmark events and so forth. This will allow groups such as the MMWG or
ERAG to provide comments. In addition, the TPL-008-1 Standard has been updated to allow each PC in
coordination with other PCs to develop their own benchmark event should the events provided by the
ERO not be adequate for Planning Coordinators to consider.

Benchmark Event Framework

Some commenters expressed that the ERO was directed to set a framework with this Reliability Standard
that included specific bounds by which the industry could conduct their extreme weather assessments. Yet,
TPL-008-1 still does not contain any specific boundary limits that could guide responsible entities in their
Extreme Weather Assessments or otherwise limit what might be contained or added to the Extreme
Weather Event Library, now or in the future. For these reasons we ask that the DT set clear bounds that
guide these Extreme Weather Assessments and set boundaries for any future changes to the Extreme
Weather Event Library.

Drafting team response:
A process has been developed to provide entities with the iterative process on how benchmark events will
be updated every five years. The process is a separate document from the TPL-008-1 Standard as some of
the specifics are not appropriate nor requirements of the TPL-008-1 Standard. For PCs who wish to work
with other PCs to develop their own benchmark events should follow the additional requirement
language added to Requirement R2. This provides the boundaries entities must follow should the events
provided by the ERO not be adequate for Planning Coordinators to consider.

Requirement R3/R4

Benchmark Event Framework

Some commenters requested the DT to clarify “other designated entities.”

Drafting team response:
The DT removed “other designated entities” from the TPL-008-1 Standard.
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Number of Studies Required

Some commenters expressed concern regarding the number of studies which must be performed,
particularly when a Planning Coordinator (PC) selects a benchmark temperature event that is different
from that of its adjacent PC(s). In that situation, each benchmark temperature event may necessitate a
significant coordination effort. It was recommended that a governing body identify the scenarios. Extreme
temperature events will typically extend beyond the footprint of a single Planning Coordinator. To avoid
putting the PCs in a position where they are required to agree on a scenario, a year and the sensitivity to
be studied, NERC or other (e.g. ERAG) should identify the extreme heat and extreme cold temperature
events to be studied. This is necessary for consistent modeling results across adjacent planning entities.
Also, as a benchmark temperature event may extend across several planning areas, the governing body
must take this into consideration when determining which extreme heat and extreme cold temperature
events are to be studied so that no planning entity is assigned more than one of each.

Drafting team response:
The DT updated the TPL-008-1 Standard to identify that one common extreme heat and one common
extreme cold benchmark planning case must be developed, as well as at least one common extreme heat
and one common extreme cold sensitivity case. This does not preclude entities from developing more cases,
but requires a minimum of one each. Per the FERC Order 896, it is important that entities are studying
common historical events in preparation for future events. The ERO will provide entities with one common
extreme heat benchmark temperature event and one common extreme cold benchmark temperature
event for PCs to study within their zones. In addition, the TPL-008-1 Standard has been updated to allow
PCs to coordinate with other PCs to develop their own benchmark event should the events provided by the
ERO not be adequate for Planning Coordinators to consider.

Extreme Weather is a Sensitivity

Some commenters expressed that Extreme Temperature Events are already a “sensitivity” to normal longterm planning cases and are built with Gen/Load/Transfer based on the extreme weather conditions of an
entity’s territory. Additionally, mandatory “sensitivity cases” seem redundant in nature. In addition,
another commenter asked if sensitivity cases could be baked in with the benchmark temperature event.
Drafting team response:
TPL-008-1 is different than TPL-001-5.1. The TPL-008-1 Standard focuses on extreme heat and extreme cold
temperature events. Entities are to select an extreme heat and cold benchmark event, develop planning
cases, and then develop sensitivity cases from that, which may indicate a different approach on how to
handle certain scenarios.
Additionally, FERC Order 896 P124 states that “we adopt the NOPR proposal and direct NERC to require the
use of sensitivity cases to demonstrate the impact of changes to the assumptions used in the benchmark
planning case. Sensitivity analyses help a transmission planner to determine if the results of the base case
are sensitive to changes in the inputs. The use of sensitivity analyses is particularly necessary when studying
extreme heat and cold events because some of the assumptions made when developing a base case may
change if temperatures change – for example, during extreme cold events, load may increase as

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temperatures decrease, while a decrease in temperature may result in a decrease in generation. We agree
with AEP, and we direct NERC to define during the Reliability Standard development process a baseline set
of sensitivities for the new or modified Reliability Standard. While we do not require the inclusion of any
specific sensitivity in this final rule, NERC should consider including conditions that vary with temperature
such as load, generation, and system transfers.” P126 continues to explain that “[w]e disagree with NYISO
and LCRA that extreme heat and cold weather impacts are already studied as sensitivities under Reliability
Standard TPL-001-5.1. Although TPL-001-5.1 mandates sensitivity analysis by varying one or more
conditions specified in the standard such as load, generation, and transfers, this analysis alone cannot
capture the complexities of extreme heat and cold weather conditions. Sensitivity analyses consider the
impact on a base case of the variability of discrete variables. Extreme heat and cold weather impacts, on
the other hand, may include numerous concurrent outages and derates which cannot be studied as part of
a single-variable sensitivity analysis.”

TPL-008-1 Cases Used for TPL-001-5.1

One commenter asked whether language can be added to ensure that entities can take credit for studies
that are run as part of the Sensitivity analysis, rather than running those studies again as part of the
assessment to be conducted under TPL-001. For example, the Extreme Temperature Assessment could take
the place of the sensitivity analysis required within the TPL-001 assessment for both the steady state and
stability analyses. Moreover, if the Extreme Temperature Assessment is essentially a type of sensitivity
analysis already, the commenter advised removing R4.2 because this would create a sensitivity case based
on a sensitivity case.
Drafting team response:
A Planning Assessment must be completed annually in accordance with TPL-001-5.1, while an Extreme
Temperature Assessment must be completed at least once every five calendar years in accordance with
the TPL-008-1 Standard. Time will be required to coordinate and develop the common cases and
therefore, may not meet what is required in TPL-001. TPL-008-1 does not speak to TPL-001; however,
both standards have different expectations. The DT does not encourage this, but if an entity decided to go
this route, it would be up to that entity to explain and demonstrate compliance with the TPL-008-1
Standard.

Concurrent/Correlated Outage Language

Some commenters expressed that in Order 896 paragraph 88, FERC directs “NERC to require under the
new or revised Reliability Standard the study of concurrent/correlated generator and transmission
outages due to extreme heat and cold events in benchmark events,” explaining in paragraph 89 that “it is
necessary that responsible entities evaluate the risk of correlated or concurrent outages and derates of all
types of generation resources and transmission facilities as a result of extreme heat and cold events.”
Commenters suggested modifying “Benchmark planning cases that include seasonal and temperature
dependent adjustments for Load, generation, Transmission, and transfers” to include
“concurrent/correlated generator and transmission outages.”

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Drafting team response:
Concurrent/correlated outages are addressed through the standard. The DT did not use language verbatim,
but the standard is laid out on adjustment of temperature data that is provided by the event selection.
Aligning with the directives set forth in FERC Order 896, which emphasizes the importance of incorporating
derated generation, transmission capacity, and the availability of generation and transmission in the
development of benchmark planning cases, it becomes imperative for responsible entities to consider
potential concurrent or correlated generation and transmission outages and/or derates within relevant
benchmark planning cases. This ensures that the benchmark planning case accurately reflects System
conditions under extreme temperatures, with generation and transmission derates and/or outages already
factored.

MOD-032 Data

Some commenters asked if the DT feels it would be necessary to add any additional data to the table in
MOD-032 to complete this work. In addition, some sought clarification on how MOD-032 will allow for the
collection of additional information related to extreme heat and cold events.
Drafting team response:
MOD-032 ensures an adequate means of data collection for transmission planning and requires applicable
registered entities to provide steady-state, dynamic, and short circuit modeling data to their Transmission
Planner(s) and Planning Coordinator(s). As outlined in R1 and Attachment 1 of MOD-032, MOD-032 allows
various data collection such as in-service status and capability associated with demand, generation, and
transmission associated with various case types, scenarios, system operating states, or conditions for the
long-term planning horizon. MOD-032 also requires applicable registered entities to provide “other
information requested by the Planning Coordinator or Transmission Planner necessary for modeling
purposes” for each of the three types of data required. Because the DT determined the responsible entities
that will be developing benchmark planning cases are limited to Planning Coordinators and Transmission
Planners, they will be able to request and receive needed data pursuant to MOD-032. Thus, the DT believes
that there is no need to update MOD-032 because it allows Planning Coordinators and Transmission
Planners to request any specific data needed for developing benchmark planning cases and sensitivity cases
required in R4 of TPL-008-1.

“Supplemented by other sources” Clarity

Some commenters requested the DT clarify what is meant by “supplemented by other sources” with the
TPL-008-1 Standard.
Drafting team response:
Requirement R4 requires the responsible entity to use data consistent with Reliability Standard MOD-032,
supplemented by other sources as needed, for developing benchmark planning cases that represent System
conditions based on selected benchmark temperature events. This aligns with directives in FERC Order 896,
paragraph 30, emphasizing the requirement of developing both benchmark planning cases and sensitivity
study cases. Requirement R4 is consistent with Reliability Standard TPL-001-5.1 in cross-referencing
Reliability Standard MOD-032, which establishes consistent modeling data requirements and reporting

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procedures for the development of planning horizon cases necessary to support analysis of the reliability
of the interconnected System. It is also consistent with Reliability Standard TPL-001-5.1 in acknowledging
that data from other sources may be required to supplement the data collected through Reliability Standard
MOD-032 procedures.

Requirement R5

Use of “System Voltage Limits”

Some comments suggested using the recently adopted NERC Glossary term “System Voltage Limits.”
Drafting team response:
The DT determined “System Voltage Limits” focuses on operations and planning information and differs
from what is used in the standard. The DT concluded to maintain the proposed language consistent with
Reliability Standard TPL-001-5.1.

Violation Risk Factor

The risk factor should be Medium to match TPL 001-5.1. Concern that level of coordination needed to
affect the standard will be significant, particularly for “smaller” entities.
Drafting team response:
The DT updated the violation risk factor in Requirement R5 to align with TPL-001-5.1 medium.

Criteria

A commenter mentioned that R5 has criteria for acceptable System steady state voltage limits, postContingency voltage deviations, and applicable Facility Ratings, and asked whether entities will also have
to have (and document) applicable thermal criteria for completing the Extreme Temperature Assessment
(e.g., allowing for the possible use of STE facility ratings post-contingency).
Drafting team response:
Requirement 5 is drafted to provide flexibility for entities to include thermal criteria depending on the level
of risk an entity is willing to take on. This requirement does not mandate which ratings are applicable and
leaves that determination up to the entity.

Jurisdiction

A commenter mentioned that in certain jurisdictions, extreme temperature ratings have been established,
but that is not necessarily the case in all jurisdictions. Will facility owners be required to establish
extreme cold or warm temperature ratings for this standard?
Drafting team response:
Requirement 5 does not require entities to establish extreme temperature ratings, it only requires entities
to identify criteria for whichever ratings are applicable.

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Requirement R6

Violation Risk Factor

The risk factor should be Medium to match TPL 001-5.1. Concern that level of coordination needed to
affect the standard will be significant, particularly for “smaller” entities.
Drafting team response:
The DT determined that based on the planning for events such as instability, uncontrolled separation, or
Cascading events would consist of a high VRF and therefore, kept the VRF as a high.

Updated Wording

Requirement 6 needs better wording to indicate instability, uncontrolled separation and cascading must
all be monitored for. The “or” makes it seem optional.
Drafting team response:
The DT mirrored language from FERC Order 896 and determined that “or” is appropriate. It is up to the
entity to use one, two or all, regarding instability, uncontrolled separation, or Cascading when completing
this requirement.

Planning Events or Contingencies

Many commenters questioned if planning events or contingencies was the correct phrasing throughout
TPL-008-1 and requested the DT be consistent throughout the standard when using this phrase/term.
Drafting team response:
The DT determined that Contingencies was the correct phrase as it is Contingencies entities will be
completing when addressing TPL-008-1.

Requirement R7
Planning Events or Contingencies

One commenter recommends modifying Table 1 to only include P0 and P1 events in accordance with the
FERC Order 896 Paragraph 113 Commission Determination that “NERC may determine whether
contingencies P1 through P7 should also apply to the new or modified Reliability Standard, or whether a
new set of contingencies should be developed.” Paragraph 113 of the Commission Determination does
not require the inclusion of events other than P0. ISO-NE believes P0 and P1 events are acceptable for
this Standard, however, P2, P4, and P7 events are not.
Drafting team response:
The DT removed everything but P0, P1, and P7. The DT finds it important that multiple Contingencies be
included; therefore, entities must develop Corrective Action Plans in the benchmark planning cases for
Table 1 P0 and P1 Contingencies, and document possible actions in the benchmark planning cases for
Table 1 P7 Contingencies and in the sensitivity cases for Table 1 P0, P1, and P7 Contingencies.

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Violation Risk Factor

The risk factor should be Medium to match TPL 001-5.1. Concern that level of coordination needed to
affect the standard will be significant, particularly for “smaller” entities.
Drafting team response:
The DT updated the violation risk factor in Requirement R7 to align with TPL-001-5.1 medium.

Requirement R8

Performance of Steady State and/or Stability Analysis

The standard does not clearly and specifically state whether steady-state and/or stability analysis is to be
performed for the identified events as TPL-001 does, for instance. The DT should consider modifying R7
to allow the responsible entity to develop a methodology or rationale in the performance of a benchmark
event to appropriately assess it for that entity’s planning area, otherwise, additional clarity in the analysis
expectations is needed. Different weather events would require a different consideration of applicable
contingencies and analysis approaches.
Drafting team response:
Requirement 4 has been updated to state one common extreme heat and one common extreme cold. In
addition, R8 has been updated to clarify that steady state and transient stability analyses are to be
performed.

Transient Confusion

Adding “transient” to qualify stability may result in more confusion in interpretation between planning
entities, auditors, and the referenced ERO. There is a requirement to document stability criteria so this
should be clear based on that documentation. Adding “transient” therefore is more detrimental than
helpful to this standard.
Drafting team response:
Transient is an understood term among industry; therefore, the DT does not feel it will cause confusion.

Additional Sensitivity Cases

Additional sensitivity studies required in R8.2 would add a significant administrative burden without more
clarification to how it benefits the long-term planning horizon.
Drafting team response:
Table 1 has been updated to require P0, P1, and P7 Contingencies. R4 has also been updated to clarify
that it is one common extreme heat and one common extreme cold benchmark planning case, as well as
at least one common extreme heat and one common extreme cold sensitivity case. In addition, this is a
directive from the FERC Order 896 P124 which states “we adopt the NOPR proposal and direct NERC to

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require the use of sensitivity cases to demonstrate the impact of changes to the assumptions used in the
benchmark planning case. Sensitivity analyses help a transmission planner to determine if the results of
the base case are sensitive to changes in the inputs. The use of sensitivity analyses is particularly
necessary when studying extreme heat and cold events because some of the assumptions made when
developing a base case may change if temperatures change – for example, during extreme cold events,
load may increase as temperatures decrease, while a decrease in temperature may result in a decrease in
generation. We agree with AEP, and we direct NERC to define during the Reliability Standard
development process a baseline set of sensitivities for the new or modified Reliability Standard. While we
do not require the inclusion of any specific sensitivity in this final rule, NERC should consider including
conditions that vary with temperature such as load, generation, and system transfers.”

Requirement R9

Regulatory Burden

Many commenters raised concerns about the requirement to submit CAPs to regulatory authorities,
suggesting it could delay approval, lacks justification, need clearer definitions, and should be limited or
removed.
Drafting team response
The DT reviewed the comments and determined that the requirement is necessary to address the directives
of Order 896, specifically the directives mentioned in the paragraphs 152 (i.e., “we direct NERC to develop
certain processes to facilitate interaction and coordination with applicable regulatory authorities or
governing bodies responsible for retail electric service as appropriate in implementing a corrective action
plan”) and 165 (i.e., “we direct NERC to require in the new or modified Reliability Standard that responsible
entities share their corrective action plans with, and solicit feedback from, applicable regulatory authorities
or governing bodies responsible for retail electric service issues”).

Clarity on Sensitivity Analysis

Various commenters questioned the necessity of a Corrective Action Plan for issues identified in sensitivity
analysis, seeking clarity on how sensitivity analysis is handled.
Drafting team response
The DT updated Requirement R9 to clarify that Corrective Action Plans are not required specifically for
addressing performance requirements related to sensitivity cases. The responsible entity must develop
Corrective Action Plan(s) when the analysis of a benchmark planning case indicates its portion of the Bulk
Electric System is unable to meet performance requirements for Table 1 P0 or P1 Contingencies.

Facility Overload Concern

Requirement 9 and Table 1 requires the development of Corrective Action Plans for P1 events where
applicable facility ratings are exceeded and steady state voltages are not within limits. This requirement
goes beyond the directives in FERC Order 896. The FERC Order is concerned with cascading, instability,
and uncontrolled islanding but not with facility overloads.

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Drafting team response
Thermal violations are a contributing factor in Cascading events and the DT did not go beyond the intent of
FERC Order 896. According to Footnote 2 from FERC Order 896: The FPA defines “Reliable Operation” as
“operating the elements of the Bulk-Power System within equipment and electric system thermal, voltage,
and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not
occur as a result of a sudden disturbance, including a cybersecurity incident, or unanticipated failure of
system elements.” 16 U.S.C. 824o(a)(4).

CAP Request

A commenter requested the DT to ‘make their CAP available’ in R9.1 to ‘make available on request.’
Drafting team response
FERC Order 896 P153 states: “We adopt our rationale set forth in the NOPR and conclude that the directive
to require the development of corrective action plans is needed for Reliable Operation of the Bulk-Power
System. Under the currently effective Reliability Standard TPL-001-5.1, planning coordinators and
transmission planners are required to evaluate possible actions to reduce the likelihood or mitigate the
consequences of extreme weather events, but are not obligated to develop corrective action plans, even if
such events are found to cause cascading outages. Experience over the past decade has demonstrated that
the potential severity of extreme heat and cold weather events exacerbates the likelihood to cause system
instability, uncontrolled separation, or cascading failures as a result of a sudden disturbance or
unanticipated failure of system elements. Thus, we conclude that entities should proactively address
known system vulnerabilities by developing corrective action plans that include mitigation for specified
instances where performance requirements for extreme heat and cold events are not met.” Therefore, it
is the responsibility of the PC or TP developing the CAPs to provide this information to the respective
governing bodies and solicit feedback per the FERC Order.

CAP Process

There are already existing processes for interactions with applicable regulatory authorities and governing
bodies regarding CAP for many other issues and items. Extreme weather CAPs are not exceptions and do
not need a new way to solicit feedback. R9.1 should be removed because it also creates a compliance
requirement without any benefit to reliability and would be confusing.
In addition, a commenter requested 9.1 subpart be removed because it creates a compliance requirement
without any incremental benefit to reliability and further conflicts with existing planning requirements
and processes.
Drafting team response
An entity may use what is already in place to be compliant with this requirement. This requirement is
addressing the FERC Order 896 directive in P152 that states “we direct NERC to develop certain processes
to facilitate interaction and coordination with applicable regulatory authorities or governing bodies
responsible for retail electric service as appropriate in implementing a corrective action plan.” Lastly, the

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TPL-008-1 Standard is aligning with what the FERC Order 896 directs. The DT did its best to algin with TPL001 while meeting the FERC Order 896 directives.

Include Threshold

One commenter believes the requirement for the notification to an applicable regulatory entity should also
include a threshold. As written, an entity would need to make a notification if a proposal tripped 0.1 MW
of non-consequential load. Recommend the DT add a threshold in a similar way as is included in TPL-001
Attachment 1.
Drafting team response
The DT does not feel that a threshold is needed in the TPL-008-1 Standard. An entity only has report
obligations if it is a part of a CAP. Depending on the mechanism used, you may not be required to report
smaller amounts of load.

Jurisdiction

One commenter expressed that the "applicable regulatory authorities... electric service" needs better
clarification and questioned what this looks like for Jurisdictional vs non-Jurisdictional. The commenter
asked the DT to provide better guidance and examples, and highly recommended using operation
procedures instead of CAPs since operation procedures have more flexibility to respond to a system’s
needs and adapt proactively.
Drafting team response
Per FERC Order 896 P165, building generation and transmission is outside the jurisdiction and left up to
the states. FERC Order 896 provides some examples of various activities that would be appropriate in
P155: “As noted by commenters, the NOPR provided examples of various activities that may be
appropriate under a corrective action plan, some of which may require state or local authorizations (e.g.,
generation or transmission development). Other examples mentioned in the NOPR include
“implementing new energy efficiency programs to decrease load, . . . transmission switching, or adjusting
transmission and generation maintenance outages based on longer-lead forecasts,” none of which involve
the construction of generation or transmission capacity. In addition, responsible entities have the option
to use controlled load shed as a mitigation measure. In sum, while responsible entities would have the
obligation to develop and implement a corrective action plan, the Commission is not directing any specific
result or content of the corrective action plan. In such circumstances, the Commission’s directive does
not exceed the jurisdictional limits set forth in section 215(i) of the FPA0.” Also, "applicable regulatory
authorities or governing bodies responsible for retail electric service issues" is in TPL-001; therefore, the
same entities may be used. Finally, this language was added based on FERC Order 896 P165: “We direct
NERC to require in the new or modified Reliability Standard that responsible entities share their corrective
action plans with, and solicit feedback from, applicable regulatory authorities or governing bodies
responsible for retail electric service issues. We agree with commenters that relevant state entities
should have the opportunity to provide input during the development of corrective action plans. Just as
this final rule seeks to ensure Reliable Operation of the Bulk-Power System during extreme heat and cold
weather events, regulatory authorities and governing bodies responsible for retail electric service are

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taking actions to ensure reliability for local stakeholders. As such, we believe that requiring responsible
entities to seek input from applicable regulatory authorities or governing bodies responsible for retail
electric service issues when developing corrective action plans could help ensure that shared
opportunities to increase system reliability are not missed. Further, as NESCOE points out, such
consultation may allow these entities to better understand “the cost implications of various approaches”
and, therefore, provide “better insight into the considerations and tradeoffs inherent in the options
available.”

Requirement R10
Remove R10

Some commenters feel that R10 requires a significant amount of work without providing additional system
reliability and suggested that this requirement be removed.
Drafting team response
The DT removed everything but P0, P1, and P7 Contingencies. The DT finds it important that multiple
Contingencies be included; therefore, entities must develop Corrective Action Plans in the benchmark
planning cases for Table 1 P0 and P1 Contingencies, and document possible actions in the benchmark
planning cases for Table 1 P7 Contingencies and in the sensitivity cases for Table 1 P0, P1, and P7
Contingencies. In addition, an Extreme Temperature Assessment must be completed once every five
calendar years.

Reasons for Requiring Possible Actions and Restrictions in Creating CAPs

Certain commenters questioned why possible actions are required for P2, P4, P5, and P7 contingencies,
while others disagreed due to limitations in creating CAPs for these contingencies.
Drafting team response
The DT reviewed the comments and affirmed that the Technical Rationale for R10 adequately clarified the
necessity for possible actions. Additionally, it is important to note that the TPL-008-1 Standard sets a
baseline to fulfill the directives from Order 896 and does not prohibit responsible entities from exceeding
these requirements.

Clarity and Communication on Possible Actions

A commenter questioned what actions the responsible entity intends to take based on the identified
"possible actions." There is uncertainty about how these actions will be executed. In addition, the
commenter suggested that these possible actions should be communicated to the operators so they can
prepare necessary plans and processes accordingly.
Drafting team response
The DT acknowledges the commenter's concerns regarding implementing possible actions and their
communication to operators. The DT asserts that Requirement 11 outlines the expected actions, mandating
responsible entities to share Extreme Temperature Assessment results with any functional entities that has
a reliability-related need to enhance readiness for extreme temperature events.

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Exclusion of P2, P4, P5, and P7 Contingencies

Some commenters proposed removing P5, citing that extreme weather conditions affect outdoor EHV
elements but do not impact protective relaying. Additionally, other comments suggested excluding P2, P4,
P5, and P7 events from TPL-008-1.
Drafting team response
The DT reviewed the comments and updated Requirement 10 and Table 1 to remove the P5 Contingency
from the TPL-008-1 Standard. The rationale for this decision is detailed in the Technical Rationale of R10.

TPs Ability to Create CAPs

A commenter disagrees with R10 because the requirement does not give TPs the ability to create CAPs for
the listed contingencies.
Drafting team response
Requirement 10 does not preclude Transmission Planners from developing CAPs; however, possible actions
would be required should a Transmission Planner determine that a CAP is not required.

Requirement R11

Timeline for Distributing Assessment Results

Some comments questioned if the 60 calendar days was appropriate.
Drafting team response:
The DT determined to keep the requirement unchanged as this strikes a good balance between allowing
enough time for the responsibility entity to distribute the results and the functional entity requesting the
information to receive them.

Distribution of Assessment Results

Some comments questioned if the distribution of the Extreme Temperature Assessment results should be
limited to selecting registered entities.
Drafting team response:
The DT determined to keep the requirement unchanged as it meets the following FERC directive in FERC
Order 896, Paragraph 72: “Further, responsible entities must share the study results with affected
transmission operators, transmission owners, generator owners, and other functional entities with a
reliability need for the studies.” Therefore, the responsible entity must share with any functional entity that
has a reliability related need and submits a written request for the information. Additionally, this is
consistent with other approved NERC Reliability Standards (e.g., TPL-001-5.1 and TPL-007-4).

Table 1

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16

Based on the removal of all except P0, P1, and P7 Contingencies, the table has been condensed and cleaned
up. Some comments received may no longer be applicable based on the updated Table 1. Please see the
updates in the TPL-008-1 Draft 3.

Stability Performance

A commenter asked the DT how to determine stability performance requirements for P0
events. Currently, Table 1 says that the system shall remain stable, and that instability, uncontrolled
separation and cascading shall not occur, but the commenters asked how those would occur for a P0
event.
Drafting team response:
Instability can occur during P0 conditions due to various factors like oscillations, renewable generation
behavior, and excessive power transfers. For example, poorly damped oscillations between generators in
different areas can grow and destabilize the system if not properly controlled. High levels of wind, solar,
or energy storage may also cause instability if these resources don't adequately support grid stability.
Additionally, excessive power transfers on key transmission lines can lead to voltage instability and
potential voltage collapse.

Implementation Plan
Benchmark Events

Some entities requested a date be established as to when the ERO will have the benchmark event library
published.
Drafting team response:
An ERO Benchmark Event Process document has been published with the TPL-008-1 Draft 2 posting. The
ERO benchmark event library will be published and up and running by December 2024. This library will
contain events for the first 5-year iteration of TPL-008-1. Additional time is essentially provided to entities
as the benchmark events will be published and TPL-008-1 will be pending approval from the respective
applicable governmental authorities. In addition, example benchmark event examples have been provided
in a separate document for entities to see what they will be working with to meet the TPL-008-1 Standard.
Please reference the process document for additional details on how the ERO plans to address preparing
for the next 5-year iteration of benchmark events.

Requirement R1

Many entities disagreed with making Requirement R1 effective on the effective date of TPL-008-1 because
this requirement includes the development of processes that currently do not exist.
Drafting team response:
Per FERC Order 896, Paragraph 7, “we direct NERC to ensure that the proposed new or modified Reliability
Standard becomes mandatory and enforceable beginning no later than 12 months from the effective date
of Commission approval of the new or modified Reliability Standard.” To meet this FERC directive,

Consideration of Comments | Draft 2 Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
October 2024

17

Requirement R1 is the most reasonable requirement to meet the 12-month implementation directive. 12
months from the approval date of TPL-008-1 is adequate time to identify individual and joint responsibilities
for completing the Extreme Temperature Assessment. Requirement R3 is when the process should be
developed and implemented, which per the TPL-008-1 Implementation Plan has 36-months. In addition,
there is nothing precluding entities from starting discussions with other PCs and TPs once the petition has
been submitted for approval with the respective governmental authorities.

Requirement R9

Some entities expressed concern that if R9 is intended to include the construction of capital projects, there
should be additional time allowed for construction of those projects after the completion of the first
Extreme Temperature Assessment study.
Drafting team response:
The drafting team did not change the implementation plan; however, Requirement R9.3 was added to
permit the use of Non-Consequential Load Loss as an interim solution, which normally is not permitted in
Table 1, in situations that are beyond the control of the Planning Coordinator or Transmission Planner that
prevent the implementation of a Corrective Action Plan in the required timeframe. The use of NonConsequential Load Loss as an interim solution in this situation is permitted, provided that each responsible
entity documents the situation causing the problem, alternatives evaluated, and takes actions to resolve
the situation. Additionally, Requirement R9.4 was added to permit having revisions to the CAP in
subsequent Extreme Temperature Assessments, provided that the planned BES continues to meet the
performance requirements of Table 1.

Implementation Plan Diagram

One commenter pointed out that the diagram does not line up with the Implementation Plan Language and
requested the DT update it accordingly.
Drafting team response:
The DT updated the timeframes within the Implementation Plan to line up with the intent of timing.

Technical Rationale

Please see the updated Technical Rationale document, which is located on the 2023-07 project page.

Consideration of Comments | Draft 2 Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
October 2024

18

Reminder
Standards Announcement

Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather
Additional Ballots and Non-binding Poll Open through August 22, 2024
Now Available

Additional ballots for draft two of TPL-008-1 – Transmission System Planning Performance
Requirements for Extreme Temperature Events and non-binding poll of the associated Violation
Risk Factors and Violation Severity Levels are open through 8 p.m. Eastern, Thursday, August 22,
2024.
The standard drafting team’s considerations of the responses received from the last comment
period are reflected in this draft of the standard.
Reminder Regarding Corporate RBB Memberships

Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more
than the one permitted representative in a particular Segment must withdraw the duplicate
membership(s) prior to joining new ballot pools or voting on anything as part of an existing ballot
pool. Contact [email protected] to assist with the removal of any duplicate registrations.
Balloting

Members of the ballot pools associated with this project can log in and submit their votes by accessing
the Standards Balloting and Commenting System (SBS) here.
Note: Votes cast in previous ballots, will not carry over to additional ballots. It is the responsibility of
the registered voter in the ballot pools to place votes again. To ensure a quorum is reached, if you do
not want to vote affirmative or negative, cast an abstention.
•

Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

RELIABILITY | RESILIENCE | SECURITY

•

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 ballot results will be announced and posted on the project page. The drafting team will review all
responses received during the comment period and determine the next steps of the project.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Jordan Mallory (via email) or at
404-479-7358. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists"
from the "Service" drop-down menu and specify “Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather observer list” in the Description Box.

North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Ballot Open Reminder
Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather | August 13, 2024

2

Public

Standards Announcement

Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather
Formal Comment Period Open through August 22, 2024
Now Available

A 38-day formal comment period for draft two of TPL-008-1 – Transmission System Planning
Performance Requirements for Extreme Temperature Events is open through 8 p.m. Eastern,
Thursday, August 22, 2024.
The standard drafting team’s considerations of the responses received from the previous comment
period are reflected in this draft of the standard.
Reminder Regarding Corporate RBB Memberships

Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more than
the one permitted representative in a particular Segment must withdraw the duplicate membership(s)
prior to joining new ballot pools or voting on anything as part of an existing ballot pool. Contact
[email protected] to assist with the removal of any duplicate registrations.
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. An unofficial Word
version of the comment form is posted on the project page.
•

Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.

•

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

Additional ballots for the standard and implementation plan, as well as a non-binding poll of the
associated Violation Risk Factors and Violation Severity Levels will be conducted August 13-22, 2024.
For information on the Standards Development Process, refer to the Standard Processes Manual.

RELIABILITY | RESILIENCE | SECURITY

Public

For more information or assistance, contact Senior Standards Developer, Jordan Mallory (via email) or at
404-479-7358. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists"
from the "Service" drop-down menu and specify “Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather observer list” in the Description Box.

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 2023-07 Transmission Planning Performance Requirements for Extreme Weather | July 16, 2024

2

NERC Balloting Tool (/)

Dashboard (/)

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS  
Comment: View Comment Results (/CommentResults/Index/338)
Ballot Name: 2023-07 Transmission Planning Performance Requirements for Extreme Weather TPL-008-1 AB 2 ST
Voting Start Date: 8/13/2024 12:01:00 AM
Voting End Date: 8/22/2024 8:00:00 PM
Ballot Type: ST
Ballot Activity: AB
Ballot Series: 2
Total # Votes: 276
Total Ballot Pool: 314
Quorum: 87.9
Quorum Established Date: 8/22/2024 3:45:36 PM
Weighted Segment Value: 18.17
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

89

1

10

0.139

62

0.861

0

10

7

Segment:
2

8

0.7

0

0

7

0.7

0

1

0

Segment:
3

68

1

8

0.145

47

0.855

1

5

7

Segment:
4

18

1

2

0.154

11

0.846

0

2

3

Segment:
5

76

1

8

0.163

41

0.837

0

10

17

Segment:
6

47

1

9

0.243

28

0.757

0

6

4

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

1

0

0

0

0

0

0

1

0

Segment

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

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:
9

0

0

0

0

0

0

0

0

0

Segment:
10

7

0.6

3

0.3

3

0.3

0

1

0

Totals:

314

6.3

40

1.145

199

5.155

1

36

38

Segment

BALLOT POOL MEMBERS
Show

All

Segment

entries

Organization

Search:

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power,
Inc.

Hillary Creurer

Negative

Comments
Submitted

1

Ameren - Ameren
Services

Tamara Evey

Negative

Third-Party
Comments

1

American Transmission
Company, LLC

Amy Wilke

Negative

Comments
Submitted

1

APS - Arizona Public
Service Co.

Daniela
Atanasovski

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Jennifer Bray

None

N/A

1

Associated Electric
Cooperative, Inc.

Mark Riley

Negative

Third-Party
Comments

1

Austin Energy

Thomas
Standifur

None

N/A

Negative

Comments
Submitted

1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Corporation

Segment

Organization

Voter

1

Balancing Authority of
Northern California

Kevin Smith

1

BC Hydro and Power
Authority

1

Designated
Proxy

NERC
Memo

Negative

Comments
Submitted

Adrian Andreoiu

Abstain

N/A

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

1

Black Hills Corporation

Micah Runner

Abstain

N/A

1

Bonneville Power
Administration

Kamala RogersHolliday

Negative

Comments
Submitted

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Negative

Comments
Submitted

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

Negative

Third-Party
Comments

1

Central Iowa Power
Cooperative

Kevin Lyons

Negative

Third-Party
Comments

1

City Utilities of
Springfield, Missouri

Michael Bowman

Negative

Third-Party
Comments

1

Colorado Springs Utilities

Corey Walker

Negative

Third-Party
Comments

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dairyland Power
Cooperative

Karrie Schuldt

Negative

Third-Party
Comments

1

Dominion - Dominion
Virginia Power

Steven Belle

Negative

Comments
Submitted

1

Duke Energy

Katherine Street

Negative

Comments
Submitted

1

Edison International Southern California
Edison Company

Robert Blackney

Negative

Comments
Submitted

1

Entergy

Brian Lindsey

Affirmative

N/A

1

Evergy

Kevin Frick

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Tim Kelley

Ballot

Ellese Murphy

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Eversource Energy

Joshua London

Affirmative

N/A

1

Exelon

Daniel Gacek

Negative

Comments
Submitted

1

FirstEnergy - FirstEnergy
Corporation

Theresa Ciancio

Negative

Comments
Submitted

1

Georgia Transmission
Corporation

Greg Davis

Negative

Comments
Submitted

1

Glencoe Light and Power
Commission

Terry Volkmann

Negative

Third-Party
Comments

1

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Emma Halilovic

Lidija Efremova

Negative

Comments
Submitted

1

Hydro-Quebec (HQ)

Nicolas Turcotte

Chantal Mazza

Negative

Comments
Submitted

1

IDACORP - Idaho Power
Company

Sean Steffensen

None

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Denise Sanchez

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Allie Gavin

Negative

Comments
Submitted

1

JEA

Joseph McClung

Negative

Third-Party
Comments

1

KAMO Electric
Cooperative

Micah Breedlove

Negative

Third-Party
Comments

1

Lakeland Electric

Larry Watt

Negative

Third-Party
Comments

1

Lincoln Electric System

Josh Johnson

None

N/A

1

Long Island Power
Authority

Isidoro Behar

Negative

Comments
Submitted

1

Los Angeles Department
of Water and Power

faranak sarbaz

Abstain

N/A

Negative

Comments
Submitted

1
Lower Colorado River
Matt Lewis
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Authority

Stephen
Stafford

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

LS Power Transmission,
LLC

Jennifer
Richardson

Abstain

N/A

1

M and A Electric Power
Cooperative

William Price

Negative

Third-Party
Comments

1

Manitoba Hydro

Nazra Gladu

Negative

Comments
Submitted

1

MEAG Power

David Weekley

Rebika Yitna

Negative

Comments
Submitted

1

Minnkota Power
Cooperative Inc.

Theresa Allard

Nikki CarsonMarquis

Negative

Third-Party
Comments

1

Muscatine Power and
Water

Andrew Kurriger

Negative

Third-Party
Comments

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Negative

Third-Party
Comments

1

National Grid USA

Michael Jones

Negative

Comments
Submitted

1

NB Power Corporation

Jeffrey Streifling

Negative

Comments
Submitted

1

Nebraska Public Power
District

Jamison Cawley

Negative

Third-Party
Comments

1

New York Power Authority

Daniel Valle

Negative

Comments
Submitted

1

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Negative

Comments
Submitted

1

NiSource - Northern
Indiana Public Service
Co.

Alison Nickells

Affirmative

N/A

1

Northeast Missouri
Electric Power
Cooperative

Brett Douglas

Negative

Third-Party
Comments

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Negative

Third-Party
Comments

Negative

Third-Party
Comments

1

Omaha Public Power
Doug Peterchuck
District
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Segment

Organization

Voter

1

Oncor Electric Delivery

Byron Booker

1

Orlando Utilities
Commission

1

Designated
Proxy

NERC
Memo

Negative

Comments
Submitted

Aaron Staley

Affirmative

N/A

OTP - Otter Tail Power
Company

Charles Wicklund

Negative

Third-Party
Comments

1

Pacific Gas and Electric
Company

Marco Rios

Negative

Comments
Submitted

1

Platte River Power
Authority

Marissa Archie

Negative

Third-Party
Comments

1

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Negative

Comments
Submitted

1

Portland General Electric
Co.

Brooke Jockin

None

N/A

1

PPL Electric Utilities
Corporation

Michelle
McCartney
Longo

Negative

Third-Party
Comments

1

PSEG - Public Service
Electric and Gas Co.

Karen Arnold

Negative

Third-Party
Comments

1

Public Utility District No. 1
of Chelan County

Diane E Landry

Negative

Comments
Submitted

1

Public Utility District No. 1
of Snohomish County

Alyssia Rhoads

Negative

Comments
Submitted

1

Public Utility District No. 2
of Grant County,
Washington

Joanne Anderson

Abstain

N/A

1

Sacramento Municipal
Utility District

Wei Shao

Tim Kelley

Negative

Comments
Submitted

1

Salt River Project

Laura Somak

Israel Perez

Negative

Comments
Submitted

1

Santee Cooper

Chris Wagner

Negative

Comments
Submitted

Abstain

N/A

1
SaskPower
Wayne
Guttormson
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Broc Bruton

Ballot

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Seminole Electric
Cooperative, Inc.

Kristine Ward

Negative

Comments
Submitted

1

Sempra - San Diego Gas
and Electric

Mohamed
Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Negative

Comments
Submitted

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Abstain

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Negative

Third-Party
Comments

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Abstain

N/A

1

Tennessee Valley
Authority

David Plumb

Negative

Comments
Submitted

1

Tri-State G and T
Association, Inc.

Donna Wood

Negative

Comments
Submitted

1

U.S. Bureau of
Reclamation

Richard Jackson

Abstain

N/A

1

Unisource - Tucson
Electric Power Co.

Jessica Cordero

Negative

Comments
Submitted

1

VELCO -Vermont Electric
Power Company, Inc.

Randall Buswell

Abstain

N/A

1

Western Area Power
Administration

Ben Hammer

Affirmative

N/A

1

Xcel Energy, Inc.

Eric Barry

Negative

Third-Party
Comments

2

California ISO

Darcy O'Connell

Abstain

N/A

2

Electric Reliability Council
of Texas, Inc.

Kennedy Meier

Negative

Comments
Submitted

2

Independent Electricity
System Operator

Helen Lainis

Negative

Comments
Submitted

2

ISO New England, Inc.

John Pearson

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Keith Jonassen

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

2

Midcontinent ISO, Inc.

Bobbi Welch

Negative

Comments
Submitted

2

New York Independent
System Operator

Gregory Campoli

Negative

Third-Party
Comments

2

PJM Interconnection,
L.L.C.

Thomas Foster

Elizabeth Davis

Negative

Third-Party
Comments

2

Southwest Power Pool,
Inc. (RTO)

Joshua Phillips

Shannon
Mickens

Negative

Comments
Submitted

3

AEP

Leshel Hutchings

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras Sr

Negative

Comments
Submitted

3

APS - Arizona Public
Service Co.

Jessica Lopez

Affirmative

N/A

3

Arkansas Electric
Cooperative Corporation

Ayslynn Mcavoy

Abstain

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Negative

Third-Party
Comments

3

Austin Energy

Lovita Griffin

None

N/A

3

Avista - Avista
Corporation

Robert Follini

Negative

Comments
Submitted

3

BC Hydro and Power
Authority

Ming Jiang

Abstain

N/A

3

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Joseph Amato

Negative

Third-Party
Comments

3

Black Hills Corporation

Josh Combs

Abstain

N/A

3

Bonneville Power
Administration

Ron Sporseen

None

N/A

3

Buckeye Power, Inc.

Tom Schmidt

Negative

Third-Party
Comments

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Negative

Third-Party
Comments

Negative

Third-Party
Comments

3
City Utilities of
Jessica
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Springfield, Missouri
Morrissey

Danielle Moskop

Carly Miller

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Negative

Comments
Submitted

3

Colorado Springs Utilities

Hillary Dobson

Negative

Third-Party
Comments

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Virginia Power

Victoria Crider

Negative

Comments
Submitted

3

DTE Energy - Detroit
Edison Company

Marvin Johnson

Abstain

N/A

3

Duke Energy - Florida
Power Corporation

Marcelo
Pesantez

Negative

Comments
Submitted

3

Edison International Southern California
Edison Company

Romel Aquino

Negative

Comments
Submitted

3

Entergy

James Keele

Affirmative

N/A

3

Evergy

Marcus Moor

Negative

Comments
Submitted

3

Eversource Energy

Vicki O'Leary

Affirmative

N/A

3

Exelon

Kinte Whitehead

Negative

Comments
Submitted

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Negative

Comments
Submitted

3

Georgia System
Operations Corporation

Scott McGough

Negative

Third-Party
Comments

3

Great River Energy

Michael
Brytowski

Negative

Third-Party
Comments

3

Imperial Irrigation District

George Kirschner

Affirmative

N/A

3

JEA

Marilyn Williams

None

N/A

3

Lakeland Electric

Steven Marshall

Negative

Third-Party
Comments

None

N/A

3 - NERC Ver 4.2.1.0
LincolnMachine
Electric Name:
SystemATLVPEROWEB01
Sam Christensen
© 2024

Hayden Maples

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Los Angeles Department
of Water and Power

Fausto Serratos

Abstain

N/A

3

M and A Electric Power
Cooperative

Gary Dollins

Negative

Third-Party
Comments

3

Manitoba Hydro

Mike Smith

Negative

Comments
Submitted

3

MEAG Power

Roger Brand

Negative

Comments
Submitted

3

MGE Energy - Madison
Gas and Electric Co.

Benjamin Widder

Negative

Third-Party
Comments

3

Muscatine Power and
Water

Seth Shoemaker

Negative

Third-Party
Comments

3

National Grid USA

Brian Shanahan

Negative

Third-Party
Comments

3

Nebraska Public Power
District

Tony Eddleman

Negative

Third-Party
Comments

3

New York Power Authority

Richard Machado

Negative

Comments
Submitted

3

NextEra Energy - Florida
Power and Light Co.

Karen Demos

Negative

Comments
Submitted

3

NiSource - Northern
Indiana Public Service
Co.

Steven
Taddeucci

Affirmative

N/A

3

Northern California Power
Agency

Michael Whitney

None

N/A

3

NW Electric Power
Cooperative, Inc.

Heath Henry

Negative

Third-Party
Comments

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Negative

Third-Party
Comments

3

Omaha Public Power
District

David Heins

Negative

Third-Party
Comments

3

OTP - Otter Tail Power
Company

Wendi Olson

None

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Rebika Yitna

Segment

Organization

Voter

3

Pacific Gas and Electric
Company

Sandra Ellis

3

Platte River Power
Authority

3

Designated
Proxy

NERC
Memo

Negative

Comments
Submitted

Richard Kiess

Negative

Third-Party
Comments

PNM Resources - Public
Service Company of New
Mexico

Amy
Wesselkamper

Negative

Comments
Submitted

3

Portland General Electric
Co.

Mayra Franco

Negative

Third-Party
Comments

3

PPL - Louisville Gas and
Electric Co.

James Frank

Negative

Comments
Submitted

3

PSEG - Public Service
Electric and Gas Co.

Christopher
Murphy

Negative

Third-Party
Comments

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Negative

Comments
Submitted

3

Sacramento Municipal
Utility District

Nicole Looney

Tim Kelley

Negative

Comments
Submitted

3

Salt River Project

Mathew Weber

Israel Perez

Negative

Comments
Submitted

3

Santee Cooper

Vicky Budreau

Negative

Comments
Submitted

3

Seminole Electric
Cooperative, Inc.

Usama Tahir

None

N/A

3

Sempra - San Diego Gas
and Electric

Bryan Bennett

Affirmative

N/A

3

Sho-Me Power Electric
Cooperative

Jarrod Murdaugh

Negative

Third-Party
Comments

3

Snohomish County PUD
No. 1

Holly Chaney

Negative

Third-Party
Comments

3

Southern Company Alabama Power
Company

Joel Dembowski

Negative

Comments
Submitted

Negative

No Comment
Submitted

3

Southern Indiana Gas
Ryan Snyder
and Electric Co.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Bob Cardle

Ballot

Segment

Organization

Voter

3

Tacoma Public Utilities
(Tacoma, WA)

John Nierenberg

3

Tennessee Valley
Authority

3

Designated
Proxy

NERC
Memo

Negative

Third-Party
Comments

Ian Grant

Negative

Comments
Submitted

Tri-State G and T
Association, Inc.

Ryan Walter

Negative

Comments
Submitted

3

Xcel Energy, Inc.

Nicholas Friebel

Negative

Third-Party
Comments

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Negative

Third-Party
Comments

4

Arkansas Electric
Cooperative Corporation

Jenni Sudduth

None

N/A

4

Austin Energy

Tony Hua

Affirmative

N/A

4

Buckeye Power, Inc.

Jason Procuniar

Negative

Third-Party
Comments

4

City Utilities of
Springfield, Missouri

Jerry Bradshaw

Negative

Third-Party
Comments

4

CMS Energy Consumers Energy
Company

Aric Root

Negative

Comments
Submitted

4

DTE Energy

Patricia Ireland

Abstain

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

Negative

Comments
Submitted

4

Georgia System
Operations Corporation

Katrina Lyons

Negative

Third-Party
Comments

4

North Carolina Electric
Membership Corporation

Richard McCall

Negative

Third-Party
Comments

4

Northern California Power
Agency

Marty Hostler

None

N/A

4

Public Utility District No. 1
of Snohomish County

John D.
Martinsen

Negative

Comments
Submitted

Abstain

N/A

4

Public Utility District No. 2
Karla Weaver
of Grant County,
Washington
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB01

Jennie Wike

Ballot

Ryan Strom

Scott Brame

Segment

Organization

Voter

4

Sacramento Municipal
Utility District

Foung Mua

4

Seminole Electric
Cooperative, Inc.

Ken Habgood

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

4

Utility Services, Inc.

4

Designated
Proxy

NERC
Memo

Negative

Comments
Submitted

None

N/A

Negative

Third-Party
Comments

Carver Powers

Affirmative

N/A

Western Power Pool

Kevin Conway

Negative

Comments
Submitted

5

AEP

Thomas Foltz

Affirmative

N/A

5

AES - AES Corporation

Ruchi Shah

None

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Negative

Third-Party
Comments

5

APS - Arizona Public
Service Co.

Andrew Smith

Affirmative

N/A

5

Associated Electric
Cooperative, Inc.

Chuck Booth

Negative

Third-Party
Comments

5

Austin Energy

Michael Dillard

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

None

N/A

5

BC Hydro and Power
Authority

Quincy Wang

Abstain

N/A

5

Berkshire Hathaway - NV
Energy

Dwanique Spiller

None

N/A

5

Black Hills Corporation

Sheila Suurmeier

Abstain

N/A

5

Bonneville Power
Administration

Juergen Bermejo

None

N/A

5

Buckeye Power, Inc.

Kevin Zemanek

Negative

Third-Party
Comments

5

California Department of
Water Resources

ASM Mostafa

None

N/A

Negative

Third-Party
Comments

5
Choctaw Generation
Rob Watson
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Limited Partnership, LLLP

Tim Kelley

Ballot

Jennie Wike

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

CMS Energy Consumers Energy
Company

David
Greyerbiehl

Negative

Comments
Submitted

5

Colorado Springs Utilities

Jeffrey Icke

Negative

Third-Party
Comments

5

Con Ed - Consolidated
Edison Co. of New York

Michelle Pagano

Affirmative

N/A

5

Constellation

Alison MacKellar

Abstain

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

Dairyland Power
Cooperative

Tommy Drea

Negative

Third-Party
Comments

5

Dominion - Dominion
Resources, Inc.

Barbara Marion

Negative

Comments
Submitted

5

DTE Energy - Detroit
Edison Company

Mohamad
Elhusseini

Abstain

N/A

5

Duke Energy

Dale Goodwine

Negative

Comments
Submitted

5

Edison International Southern California
Edison Company

Selene Willis

Negative

Comments
Submitted

5

Entergy - Entergy
Services, Inc.

Gail Golden

Affirmative

N/A

5

Evergy

Jeremy Harris

Negative

Comments
Submitted

5

FirstEnergy - FirstEnergy
Corporation

Matthew
Augustin

Negative

Comments
Submitted

5

Florida Municipal Power
Agency

Chris Gowder

None

N/A

5

Great River Energy

Jacalynn Bentz

None

N/A

5

Greybeard Compliance
Services, LLC

Mike Gabriel

Abstain

N/A

5

Grid Strategies LLC

Michael Goggin

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

LaKenya
Vannorman

Segment

Organization

Voter

5

Hydro-Quebec (HQ)

Junji Yamaguchi

5

Imperial Irrigation District

Tino Zaragoza

5

Invenergy LLC

5

Designated
Proxy

Ballot

NERC
Memo

Negative

Comments
Submitted

Affirmative

N/A

Rhonda Jones

None

N/A

JEA

John Babik

Negative

Third-Party
Comments

5

Lincoln Electric System

Brittany Millard

None

N/A

5

Los Angeles Department
of Water and Power

Robert Kerrigan

Abstain

N/A

5

Lower Colorado River
Authority

Teresa Krabe

Negative

Comments
Submitted

5

LS Power Development,
LLC

C. A. Campbell

Abstain

N/A

5

Manitoba Hydro

Kristy-Lee Young

Negative

Comments
Submitted

5

Muscatine Power and
Water

Chance Back

Negative

Third-Party
Comments

5

National Grid USA

Robin Berry

None

N/A

5

NB Power Corporation New Brunswick Power
Transmission Corporation

Fon Hiew

Negative

Comments
Submitted

5

Nebraska Public Power
District

Ronald Bender

Negative

Third-Party
Comments

5

New York Power Authority

Zahid Qayyum

Negative

Comments
Submitted

5

NextEra Energy

Richard Vendetti

Negative

Comments
Submitted

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Affirmative

N/A

5

North Carolina Electric
Membership Corporation

Reid Cashion

Negative

Third-Party
Comments

None

N/A

5
OGE Energy - Oklahoma
Patrick Wells
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Gas and Electric Co.

Denise Sanchez

Helen Zhao

Scott Brame

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Oglethorpe Power
Corporation

Donna Johnson

Negative

Third-Party
Comments

5

Omaha Public Power
District

Kayleigh
Wilkerson

Negative

Third-Party
Comments

5

Ontario Power
Generation Inc.

Constantin
Chitescu

Negative

Comments
Submitted

5

Orlando Utilities
Commission

Dania Colon

None

N/A

5

OTP - Otter Tail Power
Company

Stacy Wahlund

None

N/A

5

Pacific Gas and Electric
Company

Tyler Brun

Negative

Comments
Submitted

5

Pattern Operators LP

George E Brown

Negative

Third-Party
Comments

5

Platte River Power
Authority

Jon Osell

Negative

Third-Party
Comments

5

Portland General Electric
Co.

Ryan Olson

None

N/A

5

PSEG Nuclear LLC

Tim Kucey

None

N/A

5

Public Utility District No. 1
of Chelan County

Rebecca Zahler

Negative

Comments
Submitted

5

Public Utility District No. 1
of Snohomish County

Becky Burden

Negative

Comments
Submitted

5

Public Utility District No. 2
of Grant County,
Washington

Nikkee Hebdon

None

N/A

5

Sacramento Municipal
Utility District

Ryder Couch

Tim Kelley

Negative

Comments
Submitted

5

Salt River Project

Thomas Johnson

Israel Perez

Negative

Comments
Submitted

5

Santee Cooper

Carey Salisbury

Negative

Comments
Submitted

Negative

Comments
Submitted

5

Seminole Electric
Melanie Wong
Cooperative,
Inc.
© 2024 - NERC Ver 4.2.1.0
Machine
Name: ATLVPEROWEB01

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

Leslie Burke

Negative

Comments
Submitted

5

Southern Indiana Gas
and Electric Co.

Larry Rogers

Abstain

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Negative

Third-Party
Comments

5

Talen Generation, LLC

Donald Lock

Negative

Comments
Submitted

5

Tallahassee Electric (City
of Tallahassee, FL)

Karen Weaver

None

N/A

5

Tennessee Valley
Authority

Darren Boehm

Negative

Comments
Submitted

5

Tri-State G and T
Association, Inc.

Sergio Banuelos

Negative

Comments
Submitted

5

U.S. Bureau of
Reclamation

Wendy Kalidass

Abstain

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Negative

Third-Party
Comments

6

AEP

Mathew Miller

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Negative

Third-Party
Comments

6

APS - Arizona Public
Service Co.

Marcus Bortman

Affirmative

N/A

6

Associated Electric
Cooperative, Inc.

Brian Ackermann

Negative

Third-Party
Comments

6

Austin Energy

Imane Mrini

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Lindsay Wickizer

None

N/A

6

Black Hills Corporation

Rachel Schuldt

Abstain

N/A

Negative

Comments
Submitted

6 - NERC Ver 4.2.1.0
Bonneville
Power
Tanner Brier
© 2024
Machine
Name: ATLVPEROWEB01
Administration

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Cleco Corporation

Robert Hirchak

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Jason Chandler

Affirmative

N/A

6

Constellation

Kimberly Turco

Abstain

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Negative

Comments
Submitted

6

Duke Energy

John Sturgeon

Negative

Comments
Submitted

6

Edison International Southern California
Edison Company

Stephanie Kenny

Negative

Comments
Submitted

6

Entergy

Julie Hall

Affirmative

N/A

6

Evergy

Tiffany Lake

Negative

Comments
Submitted

6

FirstEnergy - FirstEnergy
Corporation

Stacey Sheehan

Negative

Comments
Submitted

6

Great River Energy

Brian Meloy

Negative

Third-Party
Comments

6

Imperial Irrigation District

Diana Torres

Affirmative

N/A

6

Lakeland Electric

Paul Shipps

Negative

Third-Party
Comments

6

Lincoln Electric System

Eric Ruskamp

None

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

Abstain

N/A

6

Manitoba Hydro

Brandin Stoesz

Negative

Comments
Submitted

6

Muscatine Power and
Water

Nicholas Burns

Negative

Third-Party
Comments

6

New York Power Authority

Shelly Dineen

Negative

Comments
Submitted

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

NRG - NRG Energy, Inc.

Martin Sidor

Affirmative

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Ashley F Stringer

Negative

Third-Party
Comments

6

Omaha Public Power
District

Shonda McCain

Negative

Third-Party
Comments

6

Platte River Power
Authority

Sabrina Martz

Negative

Third-Party
Comments

6

Portland General Electric
Co.

Stefanie Burke

Negative

Third-Party
Comments

6

Powerex Corporation

Raj Hundal

Abstain

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Negative

Comments
Submitted

6

PSEG - PSEG Energy
Resources and Trade
LLC

Laura Wu

None

N/A

6

Public Utility District No. 1
of Chelan County

Robert Witham

Negative

Comments
Submitted

6

Sacramento Municipal
Utility District

Charles Norton

Tim Kelley

Negative

Comments
Submitted

6

Salt River Project

Timothy Singh

Israel Perez

Negative

Comments
Submitted

6

Santee Cooper

Marty Watson

Negative

Comments
Submitted

6

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Negative

Comments
Submitted

6

Snohomish County PUD
No. 1

John Liang

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Southern Company Southern Company
Generation

Ron Carlsen

Negative

Comments
Submitted

6

Southern Indiana Gas
and Electric Co.

Kati Barr

Abstain

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

Negative

Third-Party
Comments

6

Western Area Power
Administration

Jennifer Neville

Affirmative

N/A

6

Xcel Energy, Inc.

Steve Szablya

Negative

Third-Party
Comments

8

Florida Reliability
Coordinating Council –
Member Services Division

Vince Ordax

Abstain

N/A

10

Midwest Reliability
Organization

Mark Flanary

Affirmative

N/A

10

New York State Reliability
Council

Wesley Yeomans

Negative

Third-Party
Comments

10

Northeast Power
Coordinating Council

Gerry Dunbar

Abstain

N/A

10

ReliabilityFirst

Tyler
Schwendiman

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Negative

Comments
Submitted

10

Western Electricity
Coordinating Council

Steven Rueckert

Negative

Comments
Submitted

Jennie Wike

Greg Sorenson

Previous
Showing 1 to 314 of 314 entries

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BALLOT RESULTS  
Comment: View Comment Results (/CommentResults/Index/338)
Ballot Name: 2023-07 Transmission Planning Performance Requirements for Extreme Weather Implementation Plan AB 2
OT
Voting Start Date: 8/13/2024 12:01:00 AM
Voting End Date: 8/22/2024 8:00:00 PM
Ballot Type: OT
Ballot Activity: AB
Ballot Series: 2
Total # Votes: 275
Total Ballot Pool: 314
Quorum: 87.58
Quorum Established Date: 8/22/2024 3:48:39 PM
Weighted Segment Value: 31.97

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

89

1

18

0.247

55

0.753

0

9

7

Segment:
2

8

0.5

1

0.1

4

0.4

0

2

1

Segment:
3

68

1

15

0.263

42

0.737

0

5

6

Segment:
4

18

1

3

0.231

10

0.769

0

2

3

Segment:
5

76

1

16

0.327

33

0.673

0

9

18

Segment:
6

47

1

13

0.351

24

0.649

0

6

4

Segment:
7

0

0

0

0

0

0

0

0

0

0

0

0

1

0

Segment

Segment: 1
0
0
0
8
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Negative
Votes w/o
Comment

Abstain

No
Vote

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:
9

0

0

0

0

0

0

0

0

0

Segment:
10

7

0.5

4

0.4

1

0.1

0

2

0

Totals:

314

6

70

1.918

169

4.082

0

36

39

Segment

BALLOT POOL MEMBERS
Show

All

Segment

entries

Organization

Search:

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power,
Inc.

Hillary Creurer

Negative

Comments
Submitted

1

Ameren - Ameren
Services

Tamara Evey

Negative

Third-Party
Comments

1

American Transmission
Company, LLC

Amy Wilke

Negative

Comments
Submitted

1

APS - Arizona Public
Service Co.

Daniela
Atanasovski

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Jennifer Bray

None

N/A

1

Associated Electric
Cooperative, Inc.

Mark Riley

Negative

Third-Party
Comments

1

Austin Energy

Thomas
Standifur

None

N/A

Negative

Comments
Submitted

1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Corporation

Segment

Organization

Voter

1

Balancing Authority of
Northern California

Kevin Smith

1

BC Hydro and Power
Authority

1

Designated
Proxy

NERC
Memo

Negative

Comments
Submitted

Adrian Andreoiu

Abstain

N/A

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

1

Black Hills Corporation

Micah Runner

Affirmative

N/A

1

Bonneville Power
Administration

Kamala RogersHolliday

Negative

Comments
Submitted

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Negative

Comments
Submitted

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

Negative

Third-Party
Comments

1

Central Iowa Power
Cooperative

Kevin Lyons

Negative

Third-Party
Comments

1

City Utilities of Springfield,
Missouri

Michael Bowman

Negative

Third-Party
Comments

1

Colorado Springs Utilities

Corey Walker

Negative

Third-Party
Comments

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dairyland Power
Cooperative

Karrie Schuldt

Negative

Third-Party
Comments

1

Dominion - Dominion
Virginia Power

Steven Belle

Negative

Comments
Submitted

1

Duke Energy

Katherine Street

Negative

Comments
Submitted

1

Edison International Southern California
Edison Company

Robert Blackney

Negative

Comments
Submitted

1

Entergy

Brian Lindsey

Affirmative

N/A

1

Evergy

Kevin Frick

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Tim Kelley

Ballot

Ellese Murphy

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Eversource Energy

Joshua London

Affirmative

N/A

1

Exelon

Daniel Gacek

Negative

Comments
Submitted

1

FirstEnergy - FirstEnergy
Corporation

Theresa Ciancio

Negative

Comments
Submitted

1

Georgia Transmission
Corporation

Greg Davis

Negative

Comments
Submitted

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Emma Halilovic

Lidija Efremova

Affirmative

N/A

1

Hydro-Quebec (HQ)

Nicolas Turcotte

Chantal Mazza

Negative

Comments
Submitted

1

IDACORP - Idaho Power
Company

Sean Steffensen

None

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Denise Sanchez

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Allie Gavin

Negative

Comments
Submitted

1

JEA

Joseph McClung

Negative

Third-Party
Comments

1

KAMO Electric
Cooperative

Micah Breedlove

Negative

Third-Party
Comments

1

Lakeland Electric

Larry Watt

Negative

Third-Party
Comments

1

Lincoln Electric System

Josh Johnson

None

N/A

1

Long Island Power
Authority

Isidoro Behar

Negative

Comments
Submitted

1

Los Angeles Department
of Water and Power

faranak sarbaz

Abstain

N/A

Negative

Comments
Submitted

1

Lower Colorado River
Matt Lewis
Authority
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Stephen
Stafford

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

LS Power Transmission,
LLC

Jennifer
Richardson

Abstain

N/A

1

M and A Electric Power
Cooperative

William Price

Negative

Third-Party
Comments

1

Manitoba Hydro

Nazra Gladu

Affirmative

N/A

1

MEAG Power

David Weekley

Rebika Yitna

Negative

Comments
Submitted

1

Minnkota Power
Cooperative Inc.

Theresa Allard

Nikki CarsonMarquis

Negative

Third-Party
Comments

1

Muscatine Power and
Water

Andrew Kurriger

Negative

Third-Party
Comments

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Negative

Third-Party
Comments

1

National Grid USA

Michael Jones

Negative

Comments
Submitted

1

NB Power Corporation

Jeffrey Streifling

Negative

Comments
Submitted

1

Nebraska Public Power
District

Jamison Cawley

Negative

Third-Party
Comments

1

New York Power Authority

Daniel Valle

Negative

Comments
Submitted

1

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Negative

Comments
Submitted

1

NiSource - Northern
Indiana Public Service
Co.

Alison Nickells

Affirmative

N/A

1

Northeast Missouri
Electric Power
Cooperative

Brett Douglas

Negative

Third-Party
Comments

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Negative

Third-Party
Comments

1

Omaha Public Power
District

Doug Peterchuck

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Segment

Organization

Voter

1

Oncor Electric Delivery

Byron Booker

1

Orlando Utilities
Commission

1

Designated
Proxy

NERC
Memo

Negative

Comments
Submitted

Aaron Staley

Affirmative

N/A

OTP - Otter Tail Power
Company

Charles Wicklund

Negative

Third-Party
Comments

1

Pacific Gas and Electric
Company

Marco Rios

Negative

Comments
Submitted

1

Platte River Power
Authority

Marissa Archie

Negative

Third-Party
Comments

1

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Negative

Comments
Submitted

1

Portland General Electric
Co.

Brooke Jockin

None

N/A

1

PPL Electric Utilities
Corporation

Michelle
McCartney
Longo

Negative

Comments
Submitted

1

PSEG - Public Service
Electric and Gas Co.

Karen Arnold

Negative

Third-Party
Comments

1

Public Utility District No. 1
of Chelan County

Diane E Landry

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Alyssia Rhoads

Negative

Comments
Submitted

1

Public Utility District No. 2
of Grant County,
Washington

Joanne Anderson

Abstain

N/A

1

Sacramento Municipal
Utility District

Wei Shao

Tim Kelley

Negative

Comments
Submitted

1

Salt River Project

Laura Somak

Israel Perez

Negative

Comments
Submitted

1

Santee Cooper

Chris Wagner

Negative

Comments
Submitted

Abstain

N/A

1
SaskPower
Wayne
Guttormson
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Broc Bruton

Ballot

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Seminole Electric
Cooperative, Inc.

Kristine Ward

Negative

Comments
Submitted

1

Sempra - San Diego Gas
and Electric

Mohamed
Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Abstain

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Negative

Third-Party
Comments

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Abstain

N/A

1

Tennessee Valley
Authority

David Plumb

Affirmative

N/A

1

Tri-State G and T
Association, Inc.

Donna Wood

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Abstain

N/A

1

Unisource - Tucson
Electric Power Co.

Jessica Cordero

Negative

Comments
Submitted

1

VELCO -Vermont Electric
Power Company, Inc.

Randall Buswell

Abstain

N/A

1

Western Area Power
Administration

Ben Hammer

Affirmative

N/A

1

Xcel Energy, Inc.

Eric Barry

Negative

Third-Party
Comments

2

California ISO

Darcy O'Connell

Abstain

N/A

2

Electric Reliability Council
of Texas, Inc.

Kennedy Meier

Affirmative

N/A

2

Independent Electricity
System Operator

Helen Lainis

Abstain

N/A

2

ISO New England, Inc.

John Pearson

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Keith Jonassen

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

2

Midcontinent ISO, Inc.

Bobbi Welch

Negative

Comments
Submitted

2

New York Independent
System Operator

Gregory Campoli

Negative

Third-Party
Comments

2

PJM Interconnection,
L.L.C.

Thomas Foster

Elizabeth Davis

None

N/A

2

Southwest Power Pool,
Inc. (RTO)

Joshua Phillips

Shannon
Mickens

Negative

Comments
Submitted

3

AEP

Leshel Hutchings

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras Sr

Negative

Comments
Submitted

3

APS - Arizona Public
Service Co.

Jessica Lopez

Affirmative

N/A

3

Arkansas Electric
Cooperative Corporation

Ayslynn Mcavoy

Abstain

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Negative

Third-Party
Comments

3

Austin Energy

Lovita Griffin

None

N/A

3

Avista - Avista
Corporation

Robert Follini

Negative

Comments
Submitted

3

BC Hydro and Power
Authority

Ming Jiang

Abstain

N/A

3

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Joseph Amato

Negative

Third-Party
Comments

3

Black Hills Corporation

Josh Combs

Affirmative

N/A

3

Bonneville Power
Administration

Ron Sporseen

None

N/A

3

Buckeye Power, Inc.

Tom Schmidt

Negative

Third-Party
Comments

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Negative

Third-Party
Comments

Negative

Third-Party
Comments

3
City Utilities of Springfield,
Jessica
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Missouri
Morrissey

Danielle Moskop

Carly Miller

Ryan Strom

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

Negative

Third-Party
Comments

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Virginia Power

Victoria Crider

Negative

Comments
Submitted

3

DTE Energy - Detroit
Edison Company

Marvin Johnson

Abstain

N/A

3

Duke Energy - Florida
Power Corporation

Marcelo
Pesantez

Negative

Comments
Submitted

3

Edison International Southern California
Edison Company

Romel Aquino

Negative

Comments
Submitted

3

Entergy

James Keele

Affirmative

N/A

3

Evergy

Marcus Moor

Negative

Comments
Submitted

3

Eversource Energy

Vicki O'Leary

Affirmative

N/A

3

Exelon

Kinte Whitehead

Negative

Comments
Submitted

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Negative

Comments
Submitted

3

Georgia System
Operations Corporation

Scott McGough

Negative

Third-Party
Comments

3

Great River Energy

Michael
Brytowski

Negative

Third-Party
Comments

3

Imperial Irrigation District

George Kirschner

Affirmative

N/A

3

JEA

Marilyn Williams

None

N/A

3

Lakeland Electric

Steven Marshall

Negative

Third-Party
Comments

None

N/A

3 - NERC Ver 4.2.1.0
LincolnMachine
Electric Name:
SystemATLVPEROWEB01
Sam Christensen
© 2024

Hayden Maples

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Los Angeles Department
of Water and Power

Fausto Serratos

Abstain

N/A

3

M and A Electric Power
Cooperative

Gary Dollins

Negative

Third-Party
Comments

3

Manitoba Hydro

Mike Smith

Affirmative

N/A

3

MEAG Power

Roger Brand

Negative

Comments
Submitted

3

MGE Energy - Madison
Gas and Electric Co.

Benjamin Widder

Negative

Third-Party
Comments

3

Muscatine Power and
Water

Seth Shoemaker

Negative

Third-Party
Comments

3

National Grid USA

Brian Shanahan

Negative

Third-Party
Comments

3

Nebraska Public Power
District

Tony Eddleman

Negative

Third-Party
Comments

3

New York Power Authority

Richard Machado

Negative

Comments
Submitted

3

NextEra Energy - Florida
Power and Light Co.

Karen Demos

Negative

Comments
Submitted

3

NiSource - Northern
Indiana Public Service
Co.

Steven
Taddeucci

Affirmative

N/A

3

Northern California Power
Agency

Michael Whitney

None

N/A

3

NW Electric Power
Cooperative, Inc.

Heath Henry

Negative

Third-Party
Comments

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Negative

Third-Party
Comments

3

Omaha Public Power
District

David Heins

Negative

Third-Party
Comments

3

OTP - Otter Tail Power
Company

Wendi Olson

None

N/A

Negative

Comments
Submitted

3

Pacific Gas and Electric
Sandra Ellis
Company
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB01

Rebika Yitna

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Platte River Power
Authority

Richard Kiess

Negative

Third-Party
Comments

3

PNM Resources - Public
Service Company of New
Mexico

Amy
Wesselkamper

Negative

Comments
Submitted

3

Portland General Electric
Co.

Mayra Franco

Negative

Third-Party
Comments

3

PPL - Louisville Gas and
Electric Co.

James Frank

Negative

Comments
Submitted

3

PSEG - Public Service
Electric and Gas Co.

Christopher
Murphy

Negative

Third-Party
Comments

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Tim Kelley

Negative

Comments
Submitted

3

Salt River Project

Mathew Weber

Israel Perez

Negative

Comments
Submitted

3

Santee Cooper

Vicky Budreau

Negative

Comments
Submitted

3

Seminole Electric
Cooperative, Inc.

Usama Tahir

Negative

Comments
Submitted

3

Sempra - San Diego Gas
and Electric

Bryan Bennett

Affirmative

N/A

3

Sho-Me Power Electric
Cooperative

Jarrod Murdaugh

Negative

Third-Party
Comments

3

Snohomish County PUD
No. 1

Holly Chaney

Negative

Third-Party
Comments

3

Southern Company Alabama Power Company

Joel Dembowski

Affirmative

N/A

3

Southern Indiana Gas
and Electric Co.

Ryan Snyder

Abstain

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

John Nierenberg

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Segment

Designated
Proxy

Voter

3

Tennessee Valley
Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T
Association, Inc.

Ryan Walter

Affirmative

N/A

3

Xcel Energy, Inc.

Nicholas Friebel

Negative

Third-Party
Comments

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Negative

Third-Party
Comments

4

Arkansas Electric
Cooperative Corporation

Jenni Sudduth

None

N/A

4

Austin Energy

Tony Hua

Affirmative

N/A

4

Buckeye Power, Inc.

Jason Procuniar

Negative

Third-Party
Comments

4

City Utilities of Springfield,
Missouri

Jerry Bradshaw

Negative

Third-Party
Comments

4

CMS Energy Consumers Energy
Company

Aric Root

Affirmative

N/A

4

DTE Energy

Patricia Ireland

Abstain

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

Negative

Comments
Submitted

4

Georgia System
Operations Corporation

Katrina Lyons

Negative

Third-Party
Comments

4

North Carolina Electric
Membership Corporation

Richard McCall

Negative

Third-Party
Comments

4

Northern California Power
Agency

Marty Hostler

None

N/A

4

Public Utility District No. 1
of Snohomish County

John D.
Martinsen

Negative

Comments
Submitted

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Abstain

N/A

Negative

Comments
Submitted

4

Sacramento Municipal
Foung Mua
Utility District
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB01

Ryan Strom

Scott Brame

Tim Kelley

Ballot

NERC
Memo

Organization

Segment

Organization

Voter

4

Seminole Electric
Cooperative, Inc.

Ken Habgood

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

4

Utility Services, Inc.

4

Designated
Proxy

Ballot

NERC
Memo

None

N/A

Negative

Third-Party
Comments

Carver Powers

Affirmative

N/A

Western Power Pool

Kevin Conway

Negative

Comments
Submitted

5

AEP

Thomas Foltz

Affirmative

N/A

5

AES - AES Corporation

Ruchi Shah

None

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Negative

Third-Party
Comments

5

APS - Arizona Public
Service Co.

Andrew Smith

Affirmative

N/A

5

Associated Electric
Cooperative, Inc.

Chuck Booth

Negative

Third-Party
Comments

5

Austin Energy

Michael Dillard

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

None

N/A

5

BC Hydro and Power
Authority

Quincy Wang

Abstain

N/A

5

Berkshire Hathaway - NV
Energy

Dwanique Spiller

None

N/A

5

Black Hills Corporation

Sheila Suurmeier

Affirmative

N/A

5

Bonneville Power
Administration

Juergen Bermejo

None

N/A

5

Buckeye Power, Inc.

Kevin Zemanek

Negative

Third-Party
Comments

5

California Department of
Water Resources

ASM Mostafa

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

CMS Energy Consumers Energy
Company

David
Greyerbiehl

Affirmative

N/A

5

Colorado Springs Utilities

Jeffrey Icke

Negative

Third-Party
Comments

5

Con Ed - Consolidated
Edison Co. of New York

Michelle Pagano

Affirmative

N/A

5

Constellation

Alison MacKellar

Abstain

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

Dairyland Power
Cooperative

Tommy Drea

Negative

Third-Party
Comments

5

Dominion - Dominion
Resources, Inc.

Barbara Marion

Negative

Comments
Submitted

5

DTE Energy - Detroit
Edison Company

Mohamad
Elhusseini

Abstain

N/A

5

Duke Energy

Dale Goodwine

Negative

Comments
Submitted

5

Edison International Southern California
Edison Company

Selene Willis

Negative

Comments
Submitted

5

Entergy - Entergy
Services, Inc.

Gail Golden

Affirmative

N/A

5

Evergy

Jeremy Harris

Negative

Comments
Submitted

5

FirstEnergy - FirstEnergy
Corporation

Matthew
Augustin

Negative

Comments
Submitted

5

Florida Municipal Power
Agency

Chris Gowder

None

N/A

5

Great River Energy

Jacalynn Bentz

None

N/A

5

Greybeard Compliance
Services, LLC

Mike Gabriel

Abstain

N/A

5

Grid Strategies LLC

Michael Goggin

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

LaKenya
Vannorman

Segment

Organization

Voter

5

Hydro-Quebec (HQ)

Junji Yamaguchi

5

Imperial Irrigation District

Tino Zaragoza

5

Invenergy LLC

5

Designated
Proxy

Ballot

NERC
Memo

Negative

Comments
Submitted

Affirmative

N/A

Rhonda Jones

None

N/A

JEA

John Babik

Negative

Third-Party
Comments

5

Lincoln Electric System

Brittany Millard

None

N/A

5

Los Angeles Department
of Water and Power

Robert Kerrigan

Abstain

N/A

5

Lower Colorado River
Authority

Teresa Krabe

Negative

Comments
Submitted

5

LS Power Development,
LLC

C. A. Campbell

Abstain

N/A

5

Manitoba Hydro

Kristy-Lee Young

Affirmative

N/A

5

Muscatine Power and
Water

Chance Back

Negative

Third-Party
Comments

5

National Grid USA

Robin Berry

None

N/A

5

NB Power Corporation New Brunswick Power
Transmission Corporation

Fon Hiew

Negative

Comments
Submitted

5

Nebraska Public Power
District

Ronald Bender

Negative

Third-Party
Comments

5

New York Power Authority

Zahid Qayyum

Negative

Comments
Submitted

5

NextEra Energy

Richard Vendetti

Negative

Comments
Submitted

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Affirmative

N/A

5

North Carolina Electric
Membership Corporation

Reid Cashion

Negative

Third-Party
Comments

None

N/A

5

OGE Energy - Oklahoma
Patrick Wells
Gas and Electric Co.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Denise Sanchez

Helen Zhao

Scott Brame

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Oglethorpe Power
Corporation

Donna Johnson

Negative

Third-Party
Comments

5

Omaha Public Power
District

Kayleigh
Wilkerson

Negative

Third-Party
Comments

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Negative

Comments
Submitted

5

Orlando Utilities
Commission

Dania Colon

None

N/A

5

OTP - Otter Tail Power
Company

Stacy Wahlund

None

N/A

5

Pacific Gas and Electric
Company

Tyler Brun

Negative

Comments
Submitted

5

Pattern Operators LP

George E Brown

Negative

Third-Party
Comments

5

Platte River Power
Authority

Jon Osell

Negative

Third-Party
Comments

5

Portland General Electric
Co.

Ryan Olson

None

N/A

5

PSEG Nuclear LLC

Tim Kucey

None

N/A

5

Public Utility District No. 1
of Chelan County

Rebecca Zahler

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Becky Burden

Negative

Comments
Submitted

5

Public Utility District No. 2
of Grant County,
Washington

Nikkee Hebdon

None

N/A

5

Sacramento Municipal
Utility District

Ryder Couch

Tim Kelley

Negative

Comments
Submitted

5

Salt River Project

Thomas Johnson

Israel Perez

Negative

Comments
Submitted

5

Santee Cooper

Carey Salisbury

Negative

Comments
Submitted

Negative

Comments
Submitted

5

Seminole Electric
Melanie Wong
Cooperative,
Inc.
© 2024 - NERC Ver 4.2.1.0
Machine
Name: ATLVPEROWEB01

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

Leslie Burke

Affirmative

N/A

5

Southern Indiana Gas
and Electric Co.

Larry Rogers

Abstain

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Negative

Third-Party
Comments

5

Talen Generation, LLC

Donald Lock

None

N/A

5

Tallahassee Electric (City
of Tallahassee, FL)

Karen Weaver

None

N/A

5

Tennessee Valley
Authority

Darren Boehm

Affirmative

N/A

5

Tri-State G and T
Association, Inc.

Sergio Banuelos

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Kalidass

Abstain

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Negative

Third-Party
Comments

6

AEP

Mathew Miller

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Negative

Third-Party
Comments

6

APS - Arizona Public
Service Co.

Marcus Bortman

Affirmative

N/A

6

Associated Electric
Cooperative, Inc.

Brian Ackermann

Negative

Third-Party
Comments

6

Austin Energy

Imane Mrini

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Lindsay Wickizer

None

N/A

6

Black Hills Corporation

Rachel Schuldt

Affirmative

N/A

Negative

Comments
Submitted

6

Bonneville Power
Tanner Brier
Administration
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Cleco Corporation

Robert Hirchak

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Jason Chandler

Affirmative

N/A

6

Constellation

Kimberly Turco

Abstain

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Negative

Comments
Submitted

6

Duke Energy

John Sturgeon

Negative

Comments
Submitted

6

Edison International Southern California
Edison Company

Stephanie Kenny

Negative

Comments
Submitted

6

Entergy

Julie Hall

Affirmative

N/A

6

Evergy

Tiffany Lake

Negative

Comments
Submitted

6

FirstEnergy - FirstEnergy
Corporation

Stacey Sheehan

Negative

Comments
Submitted

6

Great River Energy

Brian Meloy

Negative

Third-Party
Comments

6

Imperial Irrigation District

Diana Torres

Affirmative

N/A

6

Lakeland Electric

Paul Shipps

Negative

Third-Party
Comments

6

Lincoln Electric System

Eric Ruskamp

None

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

Abstain

N/A

6

Manitoba Hydro

Brandin Stoesz

Affirmative

N/A

6

Muscatine Power and
Water

Nicholas Burns

Negative

Third-Party
Comments

6

New York Power Authority

Shelly Dineen

Negative

Comments
Submitted

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

NRG - NRG Energy, Inc.

Martin Sidor

Affirmative

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Ashley F Stringer

Negative

Third-Party
Comments

6

Omaha Public Power
District

Shonda McCain

Negative

Third-Party
Comments

6

Platte River Power
Authority

Sabrina Martz

Negative

Third-Party
Comments

6

Portland General Electric
Co.

Stefanie Burke

Abstain

N/A

6

Powerex Corporation

Raj Hundal

Abstain

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Negative

Comments
Submitted

6

PSEG - PSEG Energy
Resources and Trade
LLC

Laura Wu

None

N/A

6

Public Utility District No. 1
of Chelan County

Robert Witham

Affirmative

N/A

6

Sacramento Municipal
Utility District

Charles Norton

Tim Kelley

Negative

Comments
Submitted

6

Salt River Project

Timothy Singh

Israel Perez

Negative

Comments
Submitted

6

Santee Cooper

Marty Watson

Negative

Comments
Submitted

6

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Negative

Comments
Submitted

6

Snohomish County PUD
No. 1

John Liang

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Southern Indiana Gas
and Electric Co.

Kati Barr

Abstain

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

Negative

Third-Party
Comments

6

Western Area Power
Administration

Jennifer Neville

Affirmative

N/A

6

Xcel Energy, Inc.

Steve Szablya

Negative

Third-Party
Comments

8

Florida Reliability
Coordinating Council –
Member Services Division

Vince Ordax

Abstain

N/A

10

Midwest Reliability
Organization

Mark Flanary

Affirmative

N/A

10

New York State Reliability
Council

Wesley Yeomans

Affirmative

N/A

10

Northeast Power
Coordinating Council

Gerry Dunbar

Abstain

N/A

10

ReliabilityFirst

Tyler
Schwendiman

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Negative

Comments
Submitted

10

Western Electricity
Coordinating Council

Steven Rueckert

Abstain

N/A

Jennie Wike

Greg Sorenson

Previous
Showing 1 to 314 of 314 entries

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

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NERC Balloting Tool (/)

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BALLOT RESULTS  
Ballot Name: 2023-07 Transmission Planning Performance Requirements for Extreme Weather TPL-008-1 | Non-binding Poll
AB 2 NB
Voting Start Date: 8/13/2024 12:01:00 AM
Voting End Date: 8/22/2024 8:00:00 PM
Ballot Type: NB
Ballot Activity: AB
Ballot Series: 2
Total # Votes: 258
Total Ballot Pool: 297
Quorum: 86.87
Quorum Established Date: 8/22/2024 3:49:21 PM
Weighted Segment Value: 20.71
Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
1

86

1

11

0.183

49

0.817

18

8

Segment:
2

7

0.4

0

0

4

0.4

3

0

Segment:
3

63

1

8

0.178

37

0.822

10

7

Segment:
4

18

1

2

0.154

11

0.846

2

3

Segment:
5

72

1

8

0.195

33

0.805

14

17

Segment:
6

44

1

9

0.29

22

0.71

9

4

Segment:
7

0

0

0

0

0

0

0

0

Segment:
8

1

0

0

0

0

0

1

0

Segment:
9

0

0

0

0

0

0

0

0

Segment

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
10

6

0.4

3

0.3

1

0.1

2

0

Totals:

297

5.8

41

1.3

157

4.5

59

39

Segment

BALLOT POOL MEMBERS
Show

All

Segment

entries

Organization

Search:

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power,
Inc.

Hillary Creurer

Negative

Comments
Submitted

1

Ameren - Ameren
Services

Tamara Evey

Abstain

N/A

1

American Transmission
Company, LLC

Amy Wilke

Negative

Comments
Submitted

1

APS - Arizona Public
Service Co.

Daniela
Atanasovski

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Jennifer Bray

None

N/A

1

Associated Electric
Cooperative, Inc.

Mark Riley

Negative

Comments
Submitted

1

Austin Energy

Thomas
Standifur

None

N/A

1

Avista - Avista
Corporation

Mike Magruder

Negative

Comments
Submitted

1

Balancing Authority of
Northern California

Kevin Smith

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Tim Kelley

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

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

Micah Runner

Abstain

N/A

1

Bonneville Power
Administration

Kamala RogersHolliday

Negative

Comments
Submitted

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Negative

Comments
Submitted

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

Negative

Comments
Submitted

1

Central Iowa Power
Cooperative

Kevin Lyons

Negative

Comments
Submitted

1

City Utilities of
Springfield, Missouri

Michael Bowman

Negative

Comments
Submitted

1

Colorado Springs Utilities

Corey Walker

Negative

Comments
Submitted

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dairyland Power
Cooperative

Karrie Schuldt

Negative

Comments
Submitted

1

Dominion - Dominion
Virginia Power

Steven Belle

Negative

Comments
Submitted

1

Duke Energy

Katherine Street

Negative

Comments
Submitted

1

Edison International Southern California
Edison Company

Robert Blackney

Negative

Comments
Submitted

1

Entergy

Brian Lindsey

Affirmative

N/A

1

Evergy

Kevin Frick

Negative

Comments
Submitted

1

Eversource Energy

Joshua London

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Ellese Murphy

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Exelon

Daniel Gacek

Negative

Comments
Submitted

1

FirstEnergy - FirstEnergy
Corporation

Theresa Ciancio

Negative

Comments
Submitted

1

Georgia Transmission
Corporation

Greg Davis

Negative

Comments
Submitted

1

Glencoe Light and Power
Commission

Terry Volkmann

Abstain

N/A

1

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Emma Halilovic

Lidija Efremova

Negative

Comments
Submitted

1

Hydro-Quebec (HQ)

Nicolas Turcotte

Chantal Mazza

Negative

Comments
Submitted

1

IDACORP - Idaho Power
Company

Sean Steffensen

None

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Denise Sanchez

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Allie Gavin

Negative

Comments
Submitted

1

JEA

Joseph McClung

Negative

Comments
Submitted

1

KAMO Electric
Cooperative

Micah Breedlove

Negative

Comments
Submitted

1

Lakeland Electric

Larry Watt

Negative

Comments
Submitted

1

Lincoln Electric System

Josh Johnson

None

N/A

1

Long Island Power
Authority

Isidoro Behar

Abstain

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Abstain

N/A

1

Lower Colorado River
Authority

Matt Lewis

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Stephen
Stafford

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

LS Power Transmission,
LLC

Jennifer
Richardson

Abstain

N/A

1

M and A Electric Power
Cooperative

William Price

Negative

Comments
Submitted

1

MEAG Power

David Weekley

Rebika Yitna

Negative

Comments
Submitted

1

Minnkota Power
Cooperative Inc.

Theresa Allard

Nikki CarsonMarquis

Negative

Comments
Submitted

1

Muscatine Power and
Water

Andrew Kurriger

Negative

Comments
Submitted

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Negative

Comments
Submitted

1

National Grid USA

Michael Jones

Negative

Comments
Submitted

1

NB Power Corporation

Jeffrey Streifling

Negative

Comments
Submitted

1

Nebraska Public Power
District

Jamison Cawley

Abstain

N/A

1

New York Power Authority

Daniel Valle

Negative

Comments
Submitted

1

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Abstain

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Alison Nickells

Affirmative

N/A

1

Northeast Missouri
Electric Power
Cooperative

Brett Douglas

Negative

Comments
Submitted

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Negative

Comments
Submitted

1

Omaha Public Power
District

Doug Peterchuck

Negative

Comments
Submitted

1

Oncor Electric Delivery

Byron Booker

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Broc Bruton

Segment

Organization

Voter

1

Orlando Utilities
Commission

Aaron Staley

1

Pacific Gas and Electric
Company

Marco Rios

1

Platte River Power
Authority

1

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Negative

Comments
Submitted

Marissa Archie

Negative

Comments
Submitted

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Negative

Comments
Submitted

1

Portland General Electric
Co.

Brooke Jockin

None

N/A

1

PPL Electric Utilities
Corporation

Michelle
McCartney
Longo

None

N/A

1

PSEG - Public Service
Electric and Gas Co.

Karen Arnold

Abstain

N/A

1

Public Utility District No. 1
of Chelan County

Diane E Landry

Negative

Comments
Submitted

1

Public Utility District No. 1
of Snohomish County

Alyssia Rhoads

Negative

Comments
Submitted

1

Public Utility District No. 2
of Grant County,
Washington

Joanne Anderson

Abstain

N/A

1

Sacramento Municipal
Utility District

Wei Shao

Tim Kelley

Negative

Comments
Submitted

1

Salt River Project

Laura Somak

Israel Perez

Negative

Comments
Submitted

1

Santee Cooper

Chris Wagner

Abstain

N/A

1

SaskPower

Wayne
Guttormson

Abstain

N/A

1

Seminole Electric
Cooperative, Inc.

Kristine Ward

Negative

Comments
Submitted

Affirmative

N/A

1

Sempra - San Diego Gas
Mohamed
and Electric
Derbas
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Negative

Comments
Submitted

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Abstain

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Negative

Comments
Submitted

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Abstain

N/A

1

Tennessee Valley
Authority

David Plumb

Abstain

N/A

1

Tri-State G and T
Association, Inc.

Donna Wood

Negative

Comments
Submitted

1

U.S. Bureau of
Reclamation

Richard Jackson

Abstain

N/A

1

Unisource - Tucson
Electric Power Co.

Jessica Cordero

Negative

Comments
Submitted

1

VELCO -Vermont Electric
Power Company, Inc.

Randall Buswell

Abstain

N/A

1

Western Area Power
Administration

Ben Hammer

Affirmative

N/A

2

Electric Reliability Council
of Texas, Inc.

Kennedy Meier

Negative

Comments
Submitted

2

Independent Electricity
System Operator

Helen Lainis

Abstain

N/A

2

ISO New England, Inc.

John Pearson

Negative

Comments
Submitted

2

Midcontinent ISO, Inc.

Bobbi Welch

Negative

Comments
Submitted

2

New York Independent
System Operator

Gregory Campoli

Abstain

N/A

2

PJM Interconnection,
L.L.C.

Thomas Foster

Abstain

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Keith Jonassen

Elizabeth Davis

Segment

Organization

Voter

2

Southwest Power Pool,
Inc. (RTO)

Joshua Phillips

3

AEP

Leshel Hutchings

3

Ameren - Ameren
Services

David Jendras Sr

3

APS - Arizona Public
Service Co.

3

Designated
Proxy

NERC
Memo

Negative

Comments
Submitted

Affirmative

N/A

Abstain

N/A

Jessica Lopez

Affirmative

N/A

Arkansas Electric
Cooperative Corporation

Ayslynn Mcavoy

Abstain

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Negative

Comments
Submitted

3

Austin Energy

Lovita Griffin

None

N/A

3

Avista - Avista
Corporation

Robert Follini

Negative

Comments
Submitted

3

BC Hydro and Power
Authority

Ming Jiang

Abstain

N/A

3

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Joseph Amato

Negative

Comments
Submitted

3

Black Hills Corporation

Josh Combs

Abstain

N/A

3

Bonneville Power
Administration

Ron Sporseen

None

N/A

3

Buckeye Power, Inc.

Tom Schmidt

Negative

Comments
Submitted

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Negative

Comments
Submitted

3

City Utilities of
Springfield, Missouri

Jessica
Morrissey

Negative

Comments
Submitted

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Negative

Comments
Submitted

3

Colorado Springs Utilities

Hillary Dobson

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Shannon
Mickens

Ballot

Danielle Moskop

Carly Miller

Ryan Strom

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
Virginia Power

Victoria Crider

Negative

Comments
Submitted

3

DTE Energy - Detroit
Edison Company

Marvin Johnson

Abstain

N/A

3

Duke Energy - Florida
Power Corporation

Marcelo
Pesantez

Negative

Comments
Submitted

3

Edison International Southern California
Edison Company

Romel Aquino

Negative

Comments
Submitted

3

Entergy

James Keele

Affirmative

N/A

3

Evergy

Marcus Moor

Negative

Comments
Submitted

3

Eversource Energy

Vicki O'Leary

Affirmative

N/A

3

Exelon

Kinte Whitehead

Negative

Comments
Submitted

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Negative

Comments
Submitted

3

Great River Energy

Michael
Brytowski

Negative

Comments
Submitted

3

Imperial Irrigation District

George Kirschner

Affirmative

N/A

3

JEA

Marilyn Williams

None

N/A

3

Lakeland Electric

Steven Marshall

Negative

Comments
Submitted

3

Lincoln Electric System

Sam Christensen

None

N/A

3

M and A Electric Power
Cooperative

Gary Dollins

Negative

Comments
Submitted

3

MEAG Power

Roger Brand

Negative

Comments
Submitted

3

MGE Energy - Madison
Gas and Electric Co.

Benjamin Widder

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Denise Sanchez

Rebika Yitna

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Muscatine Power and
Water

Seth Shoemaker

Negative

Comments
Submitted

3

National Grid USA

Brian Shanahan

Negative

No Comment
Submitted

3

Nebraska Public Power
District

Tony Eddleman

Abstain

N/A

3

New York Power Authority

Richard Machado

Negative

Comments
Submitted

3

NextEra Energy - Florida
Power and Light Co.

Karen Demos

Negative

Comments
Submitted

3

NiSource - Northern
Indiana Public Service
Co.

Steven
Taddeucci

Affirmative

N/A

3

Northern California Power
Agency

Michael Whitney

None

N/A

3

NW Electric Power
Cooperative, Inc.

Heath Henry

Negative

Comments
Submitted

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Negative

Comments
Submitted

3

Omaha Public Power
District

David Heins

Negative

Comments
Submitted

3

Pacific Gas and Electric
Company

Sandra Ellis

Negative

Comments
Submitted

3

Platte River Power
Authority

Richard Kiess

Negative

Comments
Submitted

3

PNM Resources - Public
Service Company of New
Mexico

Amy
Wesselkamper

Negative

Comments
Submitted

3

Portland General Electric
Co.

Mayra Franco

Negative

Comments
Submitted

3

PPL - Louisville Gas and
Electric Co.

James Frank

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

Christopher
Murphy

Abstain

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Bob Cardle

Segment

Organization

Voter

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

3

Sacramento Municipal
Utility District

Nicole Looney

3

Salt River Project

Mathew Weber

3

Santee Cooper

3

Designated
Proxy

Ballot

NERC
Memo

Negative

Comments
Submitted

Tim Kelley

Negative

Comments
Submitted

Israel Perez

Negative

Comments
Submitted

Vicky Budreau

Abstain

N/A

Seminole Electric
Cooperative, Inc.

Usama Tahir

None

N/A

3

Sempra - San Diego Gas
and Electric

Bryan Bennett

Affirmative

N/A

3

Sho-Me Power Electric
Cooperative

Jarrod Murdaugh

Negative

Comments
Submitted

3

Snohomish County PUD
No. 1

Holly Chaney

Negative

Comments
Submitted

3

Southern Company Alabama Power
Company

Joel Dembowski

Negative

Comments
Submitted

3

Southern Indiana Gas
and Electric Co.

Ryan Snyder

Abstain

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

John Nierenberg

Negative

Comments
Submitted

3

Tennessee Valley
Authority

Ian Grant

Abstain

N/A

3

Tri-State G and T
Association, Inc.

Ryan Walter

Negative

Comments
Submitted

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Negative

Comments
Submitted

4

Arkansas Electric
Cooperative Corporation

Jenni Sudduth

None

N/A

4

Austin Energy

Tony Hua

Affirmative

N/A

4

Buckeye Power, Inc.

Jason Procuniar

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

City Utilities of
Springfield, Missouri

Jerry Bradshaw

Negative

Comments
Submitted

4

CMS Energy Consumers Energy
Company

Aric Root

Negative

Comments
Submitted

4

DTE Energy

Patricia Ireland

Abstain

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

Negative

Comments
Submitted

4

Georgia System
Operations Corporation

Katrina Lyons

Negative

Comments
Submitted

4

North Carolina Electric
Membership Corporation

Richard McCall

Negative

Comments
Submitted

4

Northern California Power
Agency

Marty Hostler

None

N/A

4

Public Utility District No. 1
of Snohomish County

John D.
Martinsen

Negative

Comments
Submitted

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Abstain

N/A

4

Sacramento Municipal
Utility District

Foung Mua

Negative

Comments
Submitted

4

Seminole Electric
Cooperative, Inc.

Ken Habgood

None

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Negative

Comments
Submitted

4

Utility Services, Inc.

Carver Powers

Affirmative

N/A

4

Western Power Pool

Kevin Conway

Negative

Comments
Submitted

5

AEP

Thomas Foltz

Affirmative

N/A

5

AES - AES Corporation

Ruchi Shah

None

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Abstain

N/A

Affirmative

N/A

5 - NERC Ver 4.2.1.0
APS - Machine
Arizona Public
Andrew Smith
© 2024
Name: ATLVPEROWEB01
Service Co.

Scott Brame

Tim Kelley

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Associated Electric
Cooperative, Inc.

Chuck Booth

Negative

Comments
Submitted

5

Austin Energy

Michael Dillard

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

None

N/A

5

BC Hydro and Power
Authority

Quincy Wang

Abstain

N/A

5

Berkshire Hathaway - NV
Energy

Dwanique Spiller

None

N/A

5

Black Hills Corporation

Sheila Suurmeier

Abstain

N/A

5

Bonneville Power
Administration

Juergen Bermejo

None

N/A

5

Buckeye Power, Inc.

Kevin Zemanek

Negative

Comments
Submitted

5

California Department of
Water Resources

ASM Mostafa

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

CMS Energy Consumers Energy
Company

David
Greyerbiehl

Negative

Comments
Submitted

5

Colorado Springs Utilities

Jeffrey Icke

Negative

Comments
Submitted

5

Con Ed - Consolidated
Edison Co. of New York

Michelle Pagano

Affirmative

N/A

5

Constellation

Alison MacKellar

Abstain

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

Dairyland Power
Cooperative

Tommy Drea

Negative

Comments
Submitted

5

Dominion - Dominion
Resources, Inc.

Barbara Marion

Negative

Comments
Submitted

Abstain

N/A

5

DTE Energy - Detroit
Mohamad
Edison Company
Elhusseini
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Duke Energy

Dale Goodwine

Negative

Comments
Submitted

5

Edison International Southern California
Edison Company

Selene Willis

Negative

Comments
Submitted

5

Entergy - Entergy
Services, Inc.

Gail Golden

Affirmative

N/A

5

Evergy

Jeremy Harris

Negative

Comments
Submitted

5

FirstEnergy - FirstEnergy
Corporation

Matthew
Augustin

Negative

Comments
Submitted

5

Florida Municipal Power
Agency

Chris Gowder

None

N/A

5

Greybeard Compliance
Services, LLC

Mike Gabriel

Abstain

N/A

5

Grid Strategies LLC

Michael Goggin

Negative

Comments
Submitted

5

Hydro-Quebec (HQ)

Junji Yamaguchi

Negative

Comments
Submitted

5

Imperial Irrigation District

Tino Zaragoza

Affirmative

N/A

5

JEA

John Babik

Negative

Comments
Submitted

5

Lincoln Electric System

Brittany Millard

None

N/A

5

Los Angeles Department
of Water and Power

Robert Kerrigan

Abstain

N/A

5

Lower Colorado River
Authority

Teresa Krabe

Negative

Comments
Submitted

5

LS Power Development,
LLC

C. A. Campbell

Abstain

N/A

5

Muscatine Power and
Water

Chance Back

Negative

Comments
Submitted

5

National Grid USA

Robin Berry

None

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

LaKenya
Vannorman

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

NB Power Corporation New Brunswick Power
Transmission Corporation

Fon Hiew

Negative

Comments
Submitted

5

Nebraska Public Power
District

Ronald Bender

Abstain

N/A

5

New York Power Authority

Zahid Qayyum

Negative

Comments
Submitted

5

NextEra Energy

Richard Vendetti

Negative

Comments
Submitted

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Affirmative

N/A

5

North Carolina Electric
Membership Corporation

Reid Cashion

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

None

N/A

5

Oglethorpe Power
Corporation

Donna Johnson

Negative

Comments
Submitted

5

Omaha Public Power
District

Kayleigh
Wilkerson

Negative

Comments
Submitted

5

Ontario Power
Generation Inc.

Constantin
Chitescu

Negative

Comments
Submitted

5

Orlando Utilities
Commission

Dania Colon

None

N/A

5

OTP - Otter Tail Power
Company

Stacy Wahlund

None

N/A

5

Pacific Gas and Electric
Company

Tyler Brun

Negative

Comments
Submitted

5

Pattern Operators LP

George E Brown

Negative

Comments
Submitted

5

Platte River Power
Authority

Jon Osell

Negative

Comments
Submitted

5

Portland General Electric
Co.

Ryan Olson

None

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Scott Brame

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

PSEG Nuclear LLC

Tim Kucey

None

N/A

5

Public Utility District No. 1
of Chelan County

Rebecca Zahler

Negative

Comments
Submitted

5

Public Utility District No. 1
of Snohomish County

Becky Burden

Negative

Comments
Submitted

5

Public Utility District No. 2
of Grant County,
Washington

Nikkee Hebdon

None

N/A

5

Sacramento Municipal
Utility District

Ryder Couch

Tim Kelley

Negative

Comments
Submitted

5

Salt River Project

Thomas Johnson

Israel Perez

Negative

Comments
Submitted

5

Santee Cooper

Carey Salisbury

Abstain

N/A

5

Seminole Electric
Cooperative, Inc.

Melanie Wong

Negative

Comments
Submitted

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

Leslie Burke

Negative

Comments
Submitted

5

Southern Indiana Gas
and Electric Co.

Larry Rogers

Abstain

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Negative

Comments
Submitted

5

Tallahassee Electric (City
of Tallahassee, FL)

Karen Weaver

None

N/A

5

Tennessee Valley
Authority

Darren Boehm

None

N/A

5

Tri-State G and T
Association, Inc.

Sergio Banuelos

Negative

Comments
Submitted

5

U.S. Bureau of
Reclamation

Wendy Kalidass

Abstain

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Abstain

N/A

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
6
AEP
Mathew Miller

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Ameren - Ameren
Services

Robert Quinlivan

Abstain

N/A

6

APS - Arizona Public
Service Co.

Marcus Bortman

Affirmative

N/A

6

Associated Electric
Cooperative, Inc.

Brian Ackermann

Negative

Comments
Submitted

6

Austin Energy

Imane Mrini

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Lindsay Wickizer

None

N/A

6

Black Hills Corporation

Rachel Schuldt

Abstain

N/A

6

Bonneville Power
Administration

Tanner Brier

Negative

Comments
Submitted

6

Con Ed - Consolidated
Edison Co. of New York

Jason Chandler

Affirmative

N/A

6

Constellation

Kimberly Turco

Abstain

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Negative

Comments
Submitted

6

Duke Energy

John Sturgeon

Negative

Comments
Submitted

6

Edison International Southern California
Edison Company

Stephanie Kenny

Negative

Comments
Submitted

6

Entergy

Julie Hall

Affirmative

N/A

6

Evergy

Tiffany Lake

Negative

Comments
Submitted

6

FirstEnergy - FirstEnergy
Corporation

Stacey Sheehan

Negative

Comments
Submitted

6

Great River Energy

Brian Meloy

Negative

Comments
Submitted

6

Imperial Irrigation District

Diana Torres

Affirmative

N/A

6

Lakeland Electric

Paul Shipps

Negative

Comments
Submitted

None

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
6
Lincoln Electric System
Eric Ruskamp

Hayden Maples

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Los Angeles Department
of Water and Power

Anton Vu

Abstain

N/A

6

Muscatine Power and
Water

Nicholas Burns

Negative

Comments
Submitted

6

New York Power Authority

Shelly Dineen

Negative

Comments
Submitted

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

Negative

Comments
Submitted

6

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

NRG - NRG Energy, Inc.

Martin Sidor

Affirmative

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Ashley F Stringer

Negative

Comments
Submitted

6

Omaha Public Power
District

Shonda McCain

Negative

Comments
Submitted

6

Platte River Power
Authority

Sabrina Martz

Negative

Comments
Submitted

6

Portland General Electric
Co.

Stefanie Burke

Abstain

N/A

6

Powerex Corporation

Raj Hundal

Abstain

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Laura Wu

None

N/A

6

Public Utility District No. 1
of Chelan County

Robert Witham

Negative

Comments
Submitted

6

Sacramento Municipal
Utility District

Charles Norton

Tim Kelley

Negative

Comments
Submitted

6

Salt River Project

Timothy Singh

Israel Perez

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Santee Cooper

Marty Watson

Abstain

N/A

6

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Negative

Comments
Submitted

6

Snohomish County PUD
No. 1

John Liang

Negative

Comments
Submitted

6

Southern Company Southern Company
Generation

Ron Carlsen

Negative

Comments
Submitted

6

Southern Indiana Gas
and Electric Co.

Kati Barr

Abstain

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

Negative

Comments
Submitted

6

Western Area Power
Administration

Jennifer Neville

Affirmative

N/A

8

Florida Reliability
Coordinating Council –
Member Services Division

Vince Ordax

Abstain

N/A

10

Midwest Reliability
Organization

Mark Flanary

Affirmative

N/A

10

Northeast Power
Coordinating Council

Gerry Dunbar

Abstain

N/A

10

ReliabilityFirst

Tyler
Schwendiman

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Abstain

N/A

10

Western Electricity
Coordinating Council

Steven Rueckert

Negative

Comments
Submitted

Jennie Wike

Greg Sorenson

Previous
Showing 1 to 297 of 297 entries

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

This is the third draft of the proposed standard posted for a 15-day formal comment period
with additional ballot.
Completed Actions

Date

Standards Committee approved Standard Authorization Request (SAR)
for posting

July 19, 2023

SAR posted for comment

August 8–September 27,
2023

45-day formal comment period with initial ballot

March 20–May 3, 2024

38-day formal comment period with additional ballot

July 16–August 22, 2024

Anticipated Actions

Date

15-day formal comment period with additional ballot

October 7–21, 2024

15-day formal comment period with additional ballot

November 7–21, 2024

5-day final ballot

December 2–6, 2024

Board adoption

December 11, 2024

Draft 3 of TPL-008-1
October 2024

Page 1 of 23

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

New or Modified Term(s) Used in NERC Reliability Standards

This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):

Extreme Temperature Assessment – Documented evaluation of future Bulk Electric System
performance for extreme heat and extreme cold benchmark temperature events.

Draft 3 of TPL-008-1
October 2024

Page 2 of 23

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements for Extreme
Temperature Events

2.

Number:

TPL-008-1

3.

Purpose:

Establish Transmission system planning performance requirements to
develop a Bulk Power System (BPS) that will operate reliably during
extreme heat and extreme cold temperature events.

4.

Applicability:
4.1. Functional Entities:
4.1.1. Transmission Planner
4.1.2. Planning Coordinator

5.

Effective Date: See Implementation Plan for Project 2023-07.

Draft 3 of TPL-008-1
October 2024

Page 3 of 23

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

B. Requirements and Measures
R1. Each Planning Coordinator shall identify, in conjunction with its Transmission
Planner(s), each entity’s individual and joint responsibilities for completing the
Extreme Temperature Assessment, which shall include each of the responsibilities
described in Requirements R2 through R11. Each responsible entity shall complete its
responsibilities such that the Extreme Temperature Assessment is completed at least
once every five calendar years. [Violation Risk Factor: Lower] [Time Horizon: Long-term
Planning]
M1. Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
provide documentation of each entity’s individual and joint responsibilities, such as
meeting minutes, agreements, copies of procedures or protocols, in effect between
entities or between departments of a vertically integrated system, or email
correspondence that identifies an agreement has been reached on individual and joint
responsibilities for completing the Extreme Temperature Assessment and that these
responsibilities were completed such that the Extreme Temperature Assessment was
completed once every five calendar years.
R2. Each Planning Coordinator shall identify the zone(s) to which the Planning Coordinator
belongs to under Attachment 1, and shall coordinate with all Planning Coordinators
within each of its identified zone(s), to select one common extreme heat benchmark
temperature event and one common extreme cold benchmark temperature event for
each of its identified zone(s) when completing the Extreme Temperature Assessment. 1
Selected benchmark temperature events shall: [Violation Risk Factor: High] [Time
Horizon: Long-term Planning]
2.1. Consider no less than a 40-year period of temperature data ending no more than
five years prior to the time the benchmark temperature events are selected; and
2.2. Represent one of the 20 most extreme temperature conditions based on the
three-day rolling average of daily maximum (heat) or daily minimum (cold)
temperature across the zone.
M2. Each Planning Coordinator shall have evidence in either electronic or hard copy format
that it identified the zone(s) to which it belongs to, under Attachment 1, and
coordinated with all other Planning Coordinators within each of its identified zone(s)
to select one common extreme heat benchmark temperature event and one common
extreme cold benchmark temperature event meeting the criteria of Requirement R2
for each of their identified zone(s) when completing the Extreme Temperature
Assessment.

1

The Electric Reliability Organization (ERO) will maintain a library of benchmark temperature events that meet the criteria of
Requirement R2.
Draft 3 of TPL-008-1
October 2024

Page 4 of 23

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R3. Each Planning Coordinator shall coordinate with all Planning Coordinators within each
of its zone(s) identified in Requirement R2, to implement a process for developing
benchmark planning cases for the Extreme Temperature Assessment that represent
the benchmark temperature events selected in Requirement R2 and sensitivity cases
to demonstrate the impact of changes to the basic assumptions used in the
benchmark planning cases. This process shall include the following: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
3.1. Selection of System models within the Long-Term Transmission Planning Horizon
to form the basis for the benchmark planning cases.
3.2. Forecasted seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers within the zone.
3.3. Assumed seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers in areas outside the zone, as needed.
3.4. Identification of changes to at least one of the following conditions for sensitivity
cases: generation, real and reactive forecasted Load, or transfers.
M3. Each Planning Coordinator shall have dated evidence that it implemented a process
for coordinating the development of benchmark planning cases and sensitivity cases
for the Extreme Temperature Assessment as specified in Requirement R3.
R4. Each responsible entity, as identified in Requirement R1, shall use the coordination
process developed in Requirement R3 and data consistent with that provided in
accordance with the MOD-032 standard, supplemented by other sources as needed,
to develop the following and establish category P0 as the normal System condition in
Table 1: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. One common extreme heat and one common extreme cold benchmark planning
case.
4.2. One common extreme heat and one common extreme cold sensitivity case.
M4. Each responsible entity, as identified in Requirement R1, shall have dated evidence in
either electronic or hard copy format that it developed benchmark planning cases and
sensitivity cases in accordance with Requirement R4.
R5. Each responsible entity, as identified in Requirement R1, shall have criteria for
acceptable System steady state voltage limits and post-Contingency voltage deviations
for completing the Extreme Temperature Assessment. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning]
M5. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of the documentation, specifying the criteria for
acceptable System steady state voltage limits and post-Contingency voltage deviations
for completing the Extreme Temperature Assessment.

Draft 3 of TPL-008-1
October 2024

Page 5 of 23

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R6. Each responsible entity, as identified in Requirement R1, shall define and document
the criteria or methodology to be used in the Extreme Temperature Assessment to
identify instability, uncontrolled separation, or Cascading within an Interconnection.
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
M6. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, specifying the criteria or
methodology to be used in the Extreme Temperature Assessment to identify
instability, uncontrolled separation, or Cascading within an Interconnection in
accordance with Requirement R6.
R7. Each responsible entity, as identified in Requirement R1, shall identify the
Contingencies for each category in Table 1 that are expected to produce more severe
System impacts on its portion of the Bulk Electric System. The rationale for those
Contingencies selected for evaluation shall be available as supporting information.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M7. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of the Contingencies for each
category in Table 1 that are expected to produce more severe System impacts on its
portion of the Bulk Electric System along with supporting rationale.
R8. Each responsible entity, as identified in Requirement R1, shall complete steady state
and transient stability analyses in the Extreme Temperature Assessment using the
Contingencies identified in Requirement R7, and shall document the assumptions and
results. Steady state and transient stability analyses shall be performed for the
following: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
8.1. Benchmark planning cases developed in accordance with Requirement R4 Part
4.1.
8.2. Sensitivity cases developed in accordance with Requirement R4 Part 4.2.
M8. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of the assumptions and results of
the steady state and transient stability analyses completed in the Extreme
Temperature Assessment.
R9. Each responsible entity, as identified in Requirement R1, shall develop a Corrective
Action Plan(s) when the analysis of a benchmark planning case, in accordance with
Requirement R8 Part 8.1, indicates its portion of the Bulk Electric System is unable to
meet performance requirements for category P0 or P1 in Table 1. For each Corrective
Action Plan, the responsible entity shall: [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]

Draft 3 of TPL-008-1
October 2024

Page 6 of 23

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

9.1. Make its Corrective Action Plan available to, and solicit feedback from, applicable
regulatory authorities or governing bodies responsible for retail electric service
issues.
9.2. Document alternative(s) considered, and notify the applicable regulatory
authorities or governing bodies responsible for retail electric service issues when
Non-Consequential Load Loss is utilized as an element of a Corrective Action Plan
for a Table 1 P1 Contingency.
9.3. Be permitted to utilize Non-Consequential Load Loss as an interim solution,
which normally is not permitted in Table 1, in situations that are beyond the
control of the Planning Coordinator or Transmission Planner that prevent the
implementation of a Corrective Action Plan in the required timeframe, provided
that the responsible entity documents the situation causing the problem,
alternatives evaluated, and takes actions to resolve the situation.
9.4. Be allowed to have revisions to the Corrective Action Plan in subsequent
Extreme Temperature Assessments, provided that the planned Bulk Electric
System shall continue to meet the performance requirements of Table 1.
M9. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of each Corrective Action Plan
developed in accordance with Requirement R9, including dated documentation of
correspondence with applicable regulatory authorities or governing bodies
responsible for retail electric service issues and any revision history, when the analysis
of a benchmark planning case indicates its portion of the Bulk Electric System is unable
to meet performance requirements for category P0 or P1 in Table 1.
R10. Each responsible entity, as identified in Requirement R1, shall evaluate and document
possible actions designed to reduce the likelihood or mitigate the consequences and
adverse impacts of the event(s) if analyses conclude there could be instability,
uncontrolled separation, or Cascading within an Interconnection, for the following:
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
10.1. Table 1 P7 Contingencies in benchmark planning cases analyzed in accordance
with Requirement R8 Part 8.1.
10.2. Categories P0, P1, and P7 in Table 1 in sensitivity cases analyzed in accordance
with Requirement R8 Part 8.2.
M10. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
such as electronic or hard copies of documentation that it evaluated and documented
possible actions designed to reduce the likelihood or mitigate the consequences and
adverse impacts when the analyses conclude there could be instability, uncontrolled
separation, or Cascading within an Interconnection for Table 1 P7 Contingencies in
benchmark planning cases or categories P0, P1, or P7 in Table 1 in sensitivity cases.
R11. Each responsible entity, as identified in Requirement R1, shall provide its Extreme
Temperature Assessment results within 60 calendar days of a request to any
Draft 3 of TPL-008-1
October 2024

Page 7 of 23

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

functional entity that has a reliability related need and submits a written request for
the information. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M11. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as email notices, documentation of updated web pages, postal receipts showing
recipient, or a demonstration of a public posting, that it provided its Extreme
Temperature Assessment to any functional entity who has a reliability need within 60
calendar days of a written request.

Draft 3 of TPL-008-1
October 2024

Page 8 of 23

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) 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 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 responsible entity shall retain evidence of compliance with each
requirement in this standard for five calendar years or one complete
Extreme Temperature Assessment cycle, whichever is longer.

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” 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.

Draft 3 of TPL-008-1
October 2024

Page 9 of 23

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events
Steady State & Stability:
a. Instability, uncontrolled separation, or Cascading within an Interconnection, defined in accordance with Requirement R6,
shall not occur.
b. Consequential Load Loss as well as generation loss is acceptable as a consequence of any event excluding P0.
c. Simulate the removal of all elements that Protection Systems and other controls are expected to automatically disconnect
for each event.
d. Simulate Normal Clearing unless otherwise specified.
e. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such
adjustments are executable within the time duration applicable to the Facility Ratings.
Steady State Only:
f. Applicable Facility Ratings shall not be exceeded.
g. System steady state voltages and post-Contingency voltage deviations shall meet the criteria identified in Requirement R5.

Draft 3 of TPL-008-1
October 2024

Page 10 of 23

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events

Category

P0
No
Contingency

P1
Single
Contingency

Initial
Condition

Normal
System

Normal
System

P7
Multiple
Contingency
(Common
Structure)

Draft 3 of TPL-008-1
October 2024

Normal
System

Event1

Fault
Type2

None

N/A

Loss of one of the following:
1. Generator
2. Transmission Circuit
3. Transformer3
4. Shunt Device4

3Ø

5. Single Pole of a DC line

SLG

The loss of:
1. Any two adjacent (vertically
or horizontally) circuits on
common structure5
2. Loss of a bipolar DC line

SLG

Interruption
of Firm
Contingency
Transmission
BES Level
Service
Allowed

Non-Consequential Load Loss
Allowed
Benchmark
Planning
Cases

Sensitivity
Cases

≥ 200 kV

Yes

No6

Yes

≥ 200 kV

Yes

Yes6

Yes

≥ 200 kV

Yes

Yes

Yes

Page 11 of 23

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events
1. If the event analyzed involves BES elements at multiple System voltage levels, the lowest System voltage level of the
element(s) removed for the analyzed event determines the BES level of the event. For P7 events, the BES level of the event is
the highest System voltage level of the element(s) removed for the analyzed event.
2. Unless specified otherwise, simulate Normal Clearing of faults. Single line to ground (SLG) or three-phase (3Ø) are the fault
types that must be evaluated in Stability simulations for the event described. A 3Ø or a double line to ground fault study
indicating the criteria are being met is sufficient evidence that a SLG condition would also meet the criteria.
3. For non-generator step up transformer outage events, the reference voltage, as used in footnote 1, applies to the low-side
winding (excluding tertiary windings). For generator and Generator Step Up transformer outage events, the reference
voltage applies to the BES connected voltage (high-side of the Generator Step Up transformer). Requirements which are
applicable to transformers also apply to variable frequency transformers and phase shifting transformers.
4. Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
5. Excludes circuits that share a common structure for 1 mile or less.
6. Benchmark planning cases require the development of a Corrective Action Plan when the responsible entity’s portion of the
BES is unable to meet the performance requirements for categories P0 or P1. Additionally, in benchmark planning cases,
Non-Consequential Load Loss is not permitted for category P0 and requires notification of applicable regulatory authorities
or governing bodies responsible for retail electric service issues when utilized as an element of a Corrective Action Plan for
P1 Contingencies. See Requirement R9 for the relevant requirements.

Draft 3 of TPL-008-1
October 2024

Page 12 of 23

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels
Violation Severity Levels

R#
R1.

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed less than
or equal to six months late.

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than six months but less than
or equal to 12 months late.

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than 12 months but less than
or equal to 18 months late.

The Planning Coordinator, in
conjunction with its
Transmission Planner(s), failed
to identify individual and joint
responsibilities for completing
the Extreme Temperature
Assessment.
OR
The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than 18 months late.

R2.

N/A

Draft 3 of TPL-008-1
October 2024

N/A

The Planning Coordinator
coordinated with all Planning
Coordinators within each
identified zone to select one
common extreme heat and
one common extreme cold
benchmark temperature event
for completing the Extreme
Temperature Assessment, but
one of the selected events

The Planning Coordinator
coordinated with all Planning
Coordinators within each
identified zone to select one
common extreme heat and
one common extreme cold
benchmark temperature event
for completing the Extreme
Temperature Assessment, but
both of the selected events

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

failed to meet all the criteria of
Requirement R2.

failed to meet all of the criteria
of Requirement R2.
OR
The Planning Coordinator
failed to coordinate with all
Planning Coordinators within
each identified zone to select
one common extreme heat
and one common extreme
cold benchmark temperature
event for completing the
Extreme Temperature
Assessment.

R3.

N/A

N/A

N/A

The Planning Coordinator did
not coordinate with all
Planning Coordinators within
each of its identified zone(s) to
implement a process for
developing benchmark
planning cases.
OR
The Planning Coordinator
coordinated with all Planning
Coordinators within each of its
identified zone(s) to
implement a process for
developing benchmark
planning cases, but the
process did not include all of
the required elements.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R4.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
did not use the coordination
process to develop benchmark
planning cases or sensitivity
cases.
OR
The responsible entity, as
identified in Requirement R1,
used the coordination process
to develop benchmark
planning cases and sensitivity
cases, but did not use data
consistent with that provided
in accordance with the MOD032 standard, supplemented
by other sources as needed,
for one or more of the
required cases.
OR
The responsible entity, as
identified in Requirement R1,
used the coordination process
and data consistent with that
provided in accordance with
the MOD-032 standard,
supplemented as needed, but
failed to develop one or more
of the required planning or
sensitivity cases.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R5.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
did not have criteria for
acceptable System steady
state voltage limits and postContingency voltage
deviations for completing the
Extreme Temperature
Assessment.

R6.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
failed to define or document
the criteria or methodology to
be used in the Extreme
Temperature Assessment to
identify instability,
uncontrolled separation, or
Cascading within an
Interconnection.

R7.

N/A

N/A

The responsible entity, as
identified in Requirement R1,
identified Contingencies for
each category in Table 1 that
are expected to produce more
severe System impacts on its
portion of the Bulk Electric
System, but did not include
the rationale for those
Contingencies selected for
evaluation as supporting
information.

The responsible entity, as
identified in Requirement R1,
did not identify Contingencies
for each category in Table 1
that are expected to produce
more severe System impacts
on its portion of the Bulk
Electric System.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for
one or more sensitivity cases
in accordance with
Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for
one or more benchmark
planning cases in accordance
with Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
evaluate and document results
for one or more of the
sensitivity cases in accordance
with Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
evaluate and document results
for one or more of the
benchmark planning cases in
accordance with Requirement
R8.
OR
The responsible entity, as
identified in Requirement R1,
failed to complete steady state
or transient stability analyses
and document results in the
Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, in
accordance with Requirement
R8.

R9.

N/A

Draft 3 of TPL-008-1
October 2024

N/A

The responsible entity, as
identified in Requirement R1,
developed a Corrective Action
Plan in accordance with
Requirement R9, but failed to
make its Corrective Action
Plan available to, or solicit

The responsible entity, as
identified in Requirement R1,
failed to develop a Corrective
Action Plan when the
benchmark planning case
study results indicate the
System is unable to meet

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R10.

N/A

N/A

feedback from, applicable
regulatory authorities or
governing bodies responsible
for retail electric service
issues.

performance requirements for
the Table 1 P0 or P1
Contingencies.

The responsible entity, as
identified in Requirement R1,
evaluated and documented
possible actions to reduce the
likelihood or mitigate the
consequences and adverse
impacts of the event(s) when
analyses conclude there could
be instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Part 10.1,
but failed to evaluate and
document possible actions
where required under
Requirement R10 Part 10.2.

The responsible entity, as
identified in Requirement R1,
evaluated and documented
possible actions to reduce the
likelihood or mitigate the
consequences and adverse
impacts of the event(s) when
analyses conclude there could
be instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Part 10.2,
but failed to evaluate and
document possible actions
where required under
Requirement R10 Part 10.1.

OR
The responsible entity, as
identified in Requirement R1,
developed a Corrective Action
Plan, but it was missing one or
more of the elements of
Requirement R9 Part 9.2-9.4
(as applicable).

OR
The responsible entity, as
identified in Requirement R1,
failed to evaluate and
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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

document possible actions to
reduce the likelihood or
mitigate the consequences
and adverse impacts of the
event(s) when analyses
conclude there could be
instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Parts 10.1
and 10.2.
R11.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 60 days but
less than or equal to 80 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 80 days but
less than or equal to 100 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 100 days but
less than or equal to 120 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 120 days
following the request.
OR
The responsible entity, as
identified in Requirement R1,
did not provide its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who submitted a written
request for the information.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

D. Regional Variances
None.

E. Associated Documents
•

Implementation Plan for Project 2023-07

•

Technical Rationale Document

•

Consideration of Issues and Directives for FERC Order 896.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Version History
Version
1

Draft 3 of TPL-008-1
October 2024

Date
TBD

Action

Change
Tracking

Addressing FERC Order 896

New Standard

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TPL-008-1 Supplemental Material

Attachment 1: Extreme Temperature Assessment Zones

The table below lists the zones to be used in the Extreme Temperature Assessment and
identifies the Planning Coordinators that belong to each zone. In accordance with Requirement
R2, each Planning Coordinator is required to identify the zone(s) to which it belongs.
Zone
MISO
SPP
PJM
NPCC (New England)
NPCC (New York)
SERC
SERC (Florida)
Central Canada
Eastern Canada

WECC Southwest
Pacific Northwest
Great Basin
Rocky Mountain
California/Mexico
Western Canada

ERCOT
Quebec

Draft 3 of TPL-008-1
October 2024

Planning Coordinators

Eastern Interconnection
MISO
SPP
PJM
Planning Coordinators in NPCC that primarily
serve the six New England States
Planning Coordinators in NPCC that primarily
serve New York
Planning Coordinators in SERC excluding those
that primarily serve Florida and those in MISO,
SPP, or PJM
Planning Coordinators in SERC that primarily
serve Florida
Planning Coordinators that primarily serve
Saskatchewan and/or Manitoba region of MRO
Planning Coordinators in NPCC that primarily
serve Ontario, New Brunswick, and Nova Scotia
Western Interconnection
Planning Coordinators in the Southwest region of
WECC, including El Paso in West Texas
Planning Coordinators in the Pacific Northwest
region of WECC
Planning Coordinators in the Great Basin region
of WECC
Planning Coordinators in the Rocky Mountain
region of WECC
Planning Coordinators in the California/Mexico
region of WECC
Planning Coordinators that primarily serve British
Columbia and/or Alberta region of WECC
ERCOT Interconnection
Areas in Texas subject to ERCOTs jurisdiction.
Quebec Interconnection
Planning Coordinators that primarily serve
Quebec in the NPCC Region.

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TPL-008-1 Supplemental Material

The map below depicts an approximation of the zones to be used in the Extreme Temperature
Assessment and is provided as a visual aid; to the extent that there is a conflict between the
map and the table, the table controls. This map is not to be used for compliance purposes.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

This is the third draft of the proposed standard posted for a 15-day formal comment period
with additional ballot.
Completed Actions

Date

Standards Committee approved Standard Authorization Request (SAR)
for posting

July 19, 2023

SAR posted for comment

August 8–September 27,
2023

45-day formal comment period with initial ballot

March 20–May 3, 2024

38-day formal comment period with additional ballot

July 16–August 22, 2024

Anticipated Actions

Date

15-day formal comment period with additional ballot

October 7–21, 2024

15-day formal comment period with additional ballot

November 7–21, 2024

5-day final ballot

December 2–6, 2024

Board adoption

December 11, 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

New or Modified Term(s) Used in NERC Reliability Standards

This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):

Extreme Temperature Assessment – Documented evaluation of future Bulk Electric System
performance for extreme heat and extreme cold benchmark temperature benchmark events.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements for Extreme
Temperature Events

2.

Number:

TPL-008-1

3.

Purpose:

Establish Transmission system planning performance requirements to
develop a Bulk Power System (BPS) that will operate reliably during
extreme heat and extreme cold temperature events.

4.

Applicability:
4.1. Functional Entities:
4.1.1. Transmission Planner
4.1.2. Planning Coordinator

5.

Effective Date: See Implementation Plan for Project 2023-07.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

B. Requirements and Measures
R1. Each Planning Coordinator shall identify, in conjunction with its Transmission
Planner(s), shall identify each entity’s individual and joint responsibilities for
completing the Extreme Temperature Assessment., which shall include each of the
responsibilities described in Requirements R2 through R11. Each responsible entity
shall complete its responsibilities such that the Extreme Temperature Assessment is
completed at least once every five calendar years. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
M1. Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
provide documentation of each entity’s individual and joint responsibilities, such as
meeting minutes, agreements, copies of procedures or protocols, in effect between
entities or between departments of a vertically integrated system, or email
correspondence that identifies an agreement has been reached on individual and joint
responsibilities for completing the Extreme Temperature Assessment and that these
responsibilities were completed such that the Extreme Temperature Assessment was
completed once every five calendar years.
R2. Each responsible entity, as Each Planning Coordinator shall identify the zone(s) to
which the Planning Coordinator belongs to under Attachment 1, and shall coordinate
with all Planning Coordinators within each of its identified in Requirement R1,
shallzone(s), to select at least one common extreme heat benchmark temperature
event and at least one common extreme cold benchmark temperature event, from the
benchmark library, approved and maintained by the Electric Reliability Organization
(ERO), for each of its identified zone(s) when completing the Extreme Temperature
Assessment.1 Selected benchmark temperature events shall: [Violation Risk Factor:
High] [Time Horizon: Long-term Planning]
2.1. Consider no less than a 40-year period of temperature data ending no more than
five years prior to the time the benchmark temperature events are selected; and
2.2. Represent one of the 20 most extreme temperature conditions based on the
three-day rolling average of daily maximum (heat) or daily minimum (cold)
temperature across the zone.
M2. Each responsible entity, as identified in Requirement R1,Planning Coordinator shall
have evidence in either electronic or hard copy format of selecting at least one
extreme heat benchmark event and at leastthat it identified the zone(s) to which it
belongs to, under Attachment 1, and coordinated with all other Planning Coordinators
within each of its identified zone(s) to select one common extreme heat benchmark
temperature event and one common extreme cold benchmark temperature event

1

The Electric Reliability Organization (ERO) will maintain a library of benchmark temperature events that meet the criteria of
Requirement R2.
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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

formeeting the criteria of Requirement R2 for each of their identified zone(s) when
completing the Extreme Temperature Assessment.
R3. Each Planning Coordinator shall develop andcoordinate with all Planning Coordinators
within each of its zone(s) identified in Requirement R2, to implement a process for
coordinating the development of developing benchmark planning cases, using for the
selected Extreme Temperature Assessment that represent the benchmark
temperature events identifiedselected in Requirement R2, Planning Coordinator(s),
Transmission Planner(s), and other designated study entities, within an. and sensitivity
cases to demonstrate the impact of changes to the basic assumptions used in the
benchmark planning cases. This process shall include the following: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
3.1. Selection of System models within the Long-Term Transmission Planning Horizon
to form the basis for the benchmark planning cases.
3.2. Forecasted seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers to represent the selected benchmark
temperature events. [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning] within the zone.
3.3. Assumed seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers in areas outside the zone, as needed.
3.4. Identification of changes to at least one of the following conditions for sensitivity
cases: generation, real and reactive forecasted Load, or transfers.
M3. Each Planning Coordinator shall have dated evidence that it developed and
implemented a process for coordinating the development of benchmark planning
cases and sensitivity cases for the Extreme Temperature Assessment as specified in
Requirement R3 that includes seasonal and temperature dependent adjustment for
Load, generation, Transmission, and transfers to represent the selected benchmark
temperature events.
R3.R4.
Each responsible entity, as identified in Requirement R1, shall use the
coordination process developed in accordance with Requirement R3 and data
consistent with that provided in accordance with the MOD-032 standard,
supplemented by other sources as needed, to develop and maintain the following and
establish category P0 as the normal System condition in Table 1: [Violation Risk Factor:
High] [Time Horizon: Long-term Planning]
3.1. Benchmark planning cases that include seasonal and temperature dependent
adjustments for Load, generation, Transmission, and transfers to represent the
System conditions of the selected benchmark temperature events as identified
in Requirement R2 for one of the years in the Long-Term Transmission Planning
Horizon. The rationale for the year selected for evaluation shall be available as

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

supporting information. This establishes Category P0 as the normal System
condition in Table 1.
3.2. Sensitivity cases to demonstrate the impact of changes to the basic assumptions
used in the benchmark planning cases. To accomplish this, the sensitivity cases
shall have changes to at least one of the following conditions:
•

Generation;

•

Real and reactive forecasted Load; or

•

Transfers.

4.1. One common extreme heat and one common extreme cold benchmark planning
case.
4.2. One common extreme heat and one common extreme cold sensitivity case.
M4. Each responsible entity, as identified in Requirement R1, shall have dated evidence in
either electronic or hard copy format that it developed and maintained benchmark
planning cases and sensitivity cases for completing the Extreme Temperature
Assessmentin accordance with Requirement R4.
R4.R5.
Each responsible entity, as identified in Requirement R1, shall have criteria for
acceptable System steady state voltage limits, and post-Contingency voltage
deviations, and applicable Facility Ratings for completing the Extreme Temperature
Assessment. [Violation Risk Factor: HighMedium] [Time Horizon: Long-term Planning]
M5. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of the documentation, specifying the criteria for
acceptable System steady state voltage limits, and post-Contingency voltage
deviations, and applicable Facility Ratings for completing the Extreme Temperature
Assessment.
R5.R6.
Each responsible entity, as identified in Requirement R1, shall define and
document the criteria or methodology to be used in the Extreme Temperature
Assessment analysis to identify instability, uncontrolled separation, or Cascading
within an Interconnection. [Violation Risk Factor: High] [Time Horizon: Long-term
Planning]
M6. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copycopies of documentation of, specifying the criteria or
methodology usedto be used in the Extreme Temperature Assessment to identify
instability, uncontrolled separation, or Cascading within an Interconnection. in
accordance with Requirement R6.
R7. Each responsible entity, as identified in Requirement R1, shall identify the planning
eventsContingencies for each category in Table 1 that are expected to produce more
severe System impacts on its portion of the Bulk Electric System. The rationale for
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those Contingencies selected for evaluation shall be available as supporting
information. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
R6. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of the Contingencies for each
category in Table 1 that are expected to produce more severe System impacts on its
portion of the Bulk Electric System. The rationale for those Contingencies selected for
evaluation shall be available as supporting information. [Violation Risk Factor: High]
[Time Horizon: Long-term Planning]
M7. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
such as electronic or hard copy documentation of the planning events for each event
category in Table 1 that are expected to produce more severe System impacts on its
portion of the Bulk Electric System along with supporting rationale.
R7.R8.
Each responsible entity, as identified in Requirement R1, shall complete steady
state and transient stability analyses in itsthe Extreme Temperature Assessment at
least once every five calendar years using the Contingencies identified in Requirement
R7, and shall document the assumptions and results of the steady. Steady state and
transient stability analyses. The Extreme Temperature Assessment shall includebe
performed for the following: [Violation Risk Factor: High] [Time Horizon: Long-term
Planning]
7.1.8.1.
Analysis of the benchmarkBenchmark planning cases developed in
accordance with Requirement R4 Part 4.1.
7.2.8.2.
Analysis of the sensitivitySensitivity cases developed in accordance with
Requirement R4 Part 4. 2.
M8. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
that it completed the , such as electronic or hard copies of documentation, of the
assumptions and results of the steady state and transient stability analyses completed
in itsthe Extreme Temperature Assessment, such as electronic or hard copies of the
analyses, meeting all the requirements in Requirement R8.
R8.R9.
Each responsible entity, as identified in Requirement R1, shall develop a
Corrective Action Plan(s) (CAPs) when the assessmentanalysis of a benchmark
planning case, in accordance with Requirement R8 Part 8.1, indicates its portion of the
Bulk Electric System is unable to meet performance requirements for Table 1category
P0 or P1 Contingencies.in Table 1. For each Corrective Action Plan, the responsible
entity shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
8.1.9.1.
Make their CAPits Corrective Action Plan available to, and solicit feedback
from, applicable regulatory authorities or governing bodies responsible for retail
electric service issues.
8.2.9.2.
Document the alternative(s) considered, and notify the applicable
regulatory authorities or governing bodies responsible for retail electric service
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issues when Non-Consequential Load Loss is utilized as an element of a
CAPCorrective Action Plan for thea Table 1 P1 Contingency.
8.3.9.3.
Be permitted to utilize Non-Consequential Load Loss as an interim
solution, which normally is not permitted in Table 1, in situations that are
beyond the control of the Planning Coordinator or Transmission Planner that
prevent the implementation of a Corrective Action Plan in the required
timeframe. The use of Non-Consequential Load Loss as an interim solution in this
situation is permitted, provided that each, provided that the responsible entity
documents the situation causing the problem, alternatives evaluated, and takes
actions to resolve the situation.
8.4.9.4.
Be allowed to have revisions to the CAPCorrective Action Plan in
subsequent Extreme Temperature Assessments, provided that the planned
BESBulk Electric System shall continue to meet the performance requirements of
Table 1.
M9. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copycopies of documentation, of each CAPCorrective Action
Plan developed for its Extreme Temperature Assessmentin accordance with
Requirement R9, including dated documentation of correspondence with applicable
regulatory authorities or governing bodies responsible for retail electric service issues
and any revision history, when the assessmentanalysis of thea benchmark planning
cases indicatecase indicates its portion of the BESBulk Electric System is unable to
meet performance requirements for Table 1category P0 or P1 Contingencies in
accordance with Requirement R9.in Table 1.
R9.R10. Each responsible entity, as identified in Requirement R1, shall evaluate and
document possible actions designed to reduce the likelihood or mitigate the
consequences and adverse impacts of the event(s) if analyses conclude there could be
instability, uncontrolled separation, or Cascading within an Interconnection, for the
following: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
9.1. Benchmark planning cases where possible actions are designed to mitigate the
consequences and adverse impacts when the study results indicate the System
could result in instability, uncontrolled separation, or Cascading for the Table 1
P2, P4, and P7 Contingencies.
9.2. Sensitivity cases where possible actions are designed to mitigate failures to
meet the performance requirements in Table 1 for category P0, P1, P2, P4, and
P7 Contingencies.
10.1. Table 1 P7 Contingencies in benchmark planning cases analyzed in accordance
with Requirement R8 Part 8.1.
10.2. Categories P0, P1, and P7 in Table 1 in sensitivity cases analyzed in accordance
with Requirement R8 Part 8.2.

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M10. Each responsible entity, as identified in Requirement R1, shall provide dated evidence
such as electronic or hard copycopies of documentation that it evaluated and
documented possible actions designed to reduce the likelihood or mitigate the
consequences and adverse impacts when the benchmark planning case study results
indicate the Systemanalyses conclude there could result inbe instability, uncontrolled
separation, or Cascading within an Interconnection for the Table 1 P2, P4, and P7
Contingencies in benchmark planning cases or categories P0, P1, or P7 in Table 1 in
sensitivity cases.
R10.R11. Each responsible entity, as identified in Requirement R1, shall provide its
Extreme Temperature Assessment results within 60 calendar days of a request to any
functional entity that has a reliability related need and submits a written request for
the information. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M11. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as email notices, documentation of updated web pages, postal receipts showing
recipient;, or a demonstration of a public posting, that it provided its Extreme
Temperature Assessment to any functional entity who has a reliability need within 60
calendar days of a written request.

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C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) 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 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 responsible entity shall retain evidence of compliance with each
requirement in this standard for five calendar years or one complete
Extreme Temperature Assessment cycle, whichever is longer.

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” 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.

Draft 3 of TPL-008-1
October 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1.1: Contingencies Category
See Footnote 2 for BES Level – Steady State & Stability Performance Events
Category
P0
No Contingency

P1
Single Contingency

P2
Single Contingency

Event

Normal System

Normal System

Normal System

Fault type

None

N/A

Loss of one of the following:
1. Generator
2. Transmission Circuit
3. Transformer
4. Shunt Device3

3Ø

5. Single Pole of a DC line

SLG

1. Opening of a line section w/o a Fault 4

N/A

2. Bus Section Fault

SLG

3. Internal Breaker Fault5
(non-Bus-tie Breaker)

SLG

4. Internal Breaker Fault (Bus-tie Breaker)5

SLG

Steady State & Stability:
a. Instability, uncontrolled separation, or Cascading within an Interconnection, defined in accordance with Requirement R6,
shall not occur.
b. Consequential Load Loss as well as generation loss is acceptable as a consequence of any event excluding P0.
c. Simulate the removal of all elements that Protection Systems and other controls are expected to automatically disconnect
for each event.
d. Simulate Normal Clearing unless otherwise specified.
Draft 3 of TPL-008-1
October 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

e. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such
adjustments are executable within the time duration applicable to the Facility Ratings.
Steady State Only:
Applicable Facility Ratings shall not be exceeded.Loss of multiple Elements caused by a stuck breaker6(non-Bus-tie Breaker) attempting to
clear a Fault on one of the following:

f.
1. System steady state voltages and post-Contingency voltage deviations shall meet the criteria identified in Requirement
R5.Generator
2. Transmission Circuit
1. Transformer
2. Shunt Device3
5. Bus Section
a.g. Loss of multiple Elements caused by a stuck breaker6 (Bus-tie Breaker) attempting to clear a Fault on the associated bus
P7
Multiple
Contingency
(Common Structure)

Draft 3 of TPL-008-1
October 2024

The loss of:
1. Any two adjacent (vertically or
horizontally) circuits on common structure
2. Loss of a bipolar DC line

SLG

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1.2: – Steady State & Stability Performance RequirementsEvents
Steady State Performance
Requirements

Stability Performance
Requirements

P0

Applicable
Facility
Ratings shall
not be
exceeded.
• System steady
state voltages
shall be within
acceptable
limits as
defined in
Requirement
R5.
The System shall
remain stable.
Instability,
uncontrolled
separation, or
Cascading, as
defined in
Requirement R6,
shall not occur.
•

•
•

P1

Applicable Facility
ratings shall not be
exceeded.
System steady state
voltages shall be
within acceptable
limits as defined in
Requirement R5.

Instability, uncontrolled
separation, or Cascading,
as defined in Requirement
R6, shall not occur.

P2

P4

P7

Instability, uncontrolled separation, or Cascading, as defined
in Requirement R6, shall not occur.

Instability, uncontrolled separation, or Cascading, as defined
in Requirement R6, shall not occur.

Requirements for Benchmark Planning Case Assessment Results
Corrective Action Plan
Required

Yes (See
Requirement R9)

Yes (See Requirement R9)

No (See Requirement R10)

Non-Consequential Load
Loss Allowed

No (See
Requirement R9)

Yes (See Requirement R9)

Yes

Draft 3 of TPL-008-1
October 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1.2: – Steady State & Stability Performance RequirementsEvents
YesNon-Consequential Load

Category

Initial
Condition

P0

Normal
SystemNo (See
No (See
Requirement
Requirement
R10)Contingency R10)

P1
Single
Contingency

P7
Multiple
Contingency
Draft 3 of TPL-008-1
October 2024

Normal System

Normal System

Event1

NoneNo (See
Requirement R10)
Non-Consequential
Load Loss of one of
the following:
1. Generator
2. Transmission
Circuit
3. Allowed
Transformer3
3.4. Shunt Device4
5. Single Pole of a
DC line
The loss of:
1. Any two
adjacent
(vertically or

Fault
Type2

N/A

Yes
3Ø

Contingency
BES Level

≥ 200 kV

Interruption of
Firm
Transmission
Service
Allowed

Loss Allowed

Benchmark
Planning Cases

Yes

No6

Requirements
for

Sensitivity

Case
Assessment
ResultsCases
Yes

Yes
≥ 200 kV

Yes

≥ 200 kV

Yes

Yes6

SLG

SLG

Yes
Yes

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1.2: – Steady State & Stability Performance RequirementsEvents
(Common
Structure)

Draft 3 of TPL-008-1
October 2024

horizontally)
circuits on
common
structure5
1.2. Loss of a
bipolar DC
lineInterruption
of Firm
Transmission
Service Allowed

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1.3 – Steady State & Stability Performance FootnotesEvents
1. If the event analyzed involves BES elements at multiple System voltage levels, the lowest System voltage level of the
element(s) removed for the analyzed event determines the BES level of the event. For P7 events, the BES level of the event is
the highest System voltage level of the element(s) removed for the analyzed event.
1.2. Unless specified otherwise, simulate Normal Clearing of faults. Single line to ground (SLG) or three-phase (3Ø) are the fault
types that must be evaluated in Stability simulations for the event described. A 3Ø or a double line to ground fault study
indicating the criteria are being met is sufficient evidence that a SLG condition would also meet the criteria.
1. Facility voltage level of Contingency is applicable to:
a. BES level 200 kV and above (referenced Contingency voltage)
b. For P7 events include Contingencies that have at least one 200kV voltage and above Facilities on common structure that
has more than one mile in length.
2.3. For non-generator step up transformer outage events, the reference voltage, as used in footnote 2a1, applies to the low-side
winding (excluding tertiary windings). For generator and Generator Step Up transformer outage events, the reference
voltage applies to the BES connected voltage (high-side of the Generator Step Up transformer). Requirements which are
applicable to transformers also apply to variable frequency transformers and phase shifting transformers.
3.4. Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
2. Opening one end of a line section without a fault on a normally networked Transmission circuit such that the line is possibly
serving Load radial from a single source point.
3. An internal breaker fault means a breaker failing internally, thus creating a System fault which must be cleared by protection
on both sides of the breaker.
5. A stuck breaker means that for a gang-operated breaker, all three phases of the breaker have remained closed. For an
independent pole operated (IPO) or an independent pole tripping (IPT) breaker, only one pole is assumed to remain closed. A
stuck breaker results in Delayed Fault Clearing.Excludes circuits that share a common structure for 1 mile or less.
4.6. Benchmark planning cases require the development of a Corrective Action Plan when the responsible entity’s portion of the
BES is unable to meet the performance requirements for categories P0 or P1. Additionally, in benchmark planning cases,
Non-Consequential Load Loss is not permitted for category P0 and requires notification of applicable regulatory authorities
or governing bodies responsible for retail electric service issues when utilized as an element of a Corrective Action Plan for
P1 Contingencies. See Requirement R9 for the relevant requirements.
Draft 3 of TPL-008-1
October 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels
Violation Severity Levels

R#
R1.

Lower VSL

Moderate VSL

High VSL

Severe VSL

N/AThe responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed less than
or equal to six months late.

N/AThe responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than six months but less than
or equal to 12 months late.

N/AThe responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than 12 months but less than
or equal to 18 months late.

The Planning Coordinator, in
conjunction with its
Transmission Planner(s), failed
to determine and identify
individual and joint
responsibilities for completing
the Extreme Temperature
Assessment.
OR
The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than 18 months late.

R2.

N/A

Draft 23 of TPL-008-1
JulyOctober 2024

N/A

The responsible entity did
notPlanning Coordinator
coordinated with all Planning
Coordinators within each
identified zone to select at
least one common extreme
heat benchmark event orand
one common extreme cold
benchmark temperature event
from the ERO approved
benchmark library for

The responsible entity did
notPlanning Coordinator
coordinated with all Planning
Coordinators within each
identified zone to select anone
common extreme heat
benchmark event andand one
common extreme cold
benchmark temperature event
for completing the Extreme
Temperature Assessment, but

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R3.

N/A

Draft 23 of TPL-008-1
JulyOctober 2024

N/A

performingcompleting the
Extreme Temperature
Assessment, but one of the
selected events failed to meet
all the criteria of Requirement
R2.

both of the selected events
failed to meet all of the criteria
of Requirement R2.

N/A

The Planning Coordinator did
not develop or coordinate with
all Planning Coordinators
within each of its identified
zone(s) to implement a
process for coordinating the
development of developing
benchmark planning cases
among impacted adjacent
Planning Coordinator(s),
Transmission Planner(s), and
other designated study
entities, within the same
Interconnection.

OR
The Planning Coordinator
failed to coordinate with all
Planning Coordinators within
each identified zone to select
one common extreme heat
and one common extreme
cold benchmark temperature
event from the ERO approved
benchmark library for
performingcompleting the
Extreme Temperature
Assessment.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

OR
The Planning Coordinator
developed and
implementedcoordinated with
all Planning Coordinators
within each of its identified
zone(s) to implement a
process for coordinating the
development of developing
benchmark planning cases
among impacted adjacent
Planning Coordinator(s),
Transmission Planner(s), and
other designated study
entities within the same
Interconnection, but thisthe
process did not modify the
benchmark planning cases to
include seasonal and
temperature dependent
adjustments load, generation,
Transmission, and transfers.
all of the required elements.
R4.

N/A

Draft 23 of TPL-008-1
JulyOctober 2024

N/A

N/A

The responsible entity did not,
as identified in Requirement
R1, did not use the
coordination process to
develop or maintain
benchmark planning cases or
sensitivity cases for
performing the Extreme
Temperature Assessment..

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

OR
The responsible entity
developed and maintained, as
identified in Requirement R1,
used the coordination process
to develop benchmark
planning cases orand
sensitivity cases for
performing the Extreme
Temperature Assessment, but
did not use data consistent
with that provided in
accordance with the MOD-032
standard., supplemented by
other sources as needed, for
one or more of the required
cases.
OR
The responsible entity, as
identified in Requirement R1,
used the coordination process
and data consistent with that
provided in accordance with
the MOD-032 standard,
supplemented as needed, but
failed to develop one or more
of the required planning or
sensitivity cases.
R5.

N/A

Draft 23 of TPL-008-1
JulyOctober 2024

N/A

N/A

The responsible entity, as
determinedidentified in
Requirement R1, did not have
criteria for acceptable System

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

steady state voltage limits, and
post-Contingency voltage
deviations, and applicable
Facility Ratings for
performingcompleting the
Extreme Temperature
Assessment.
R6.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
failed to define andor
document, the criteria or
methodology to be used in the
analysisExtreme Temperature
Assessment to identify System
instability, uncontrolled
separation, or Cascading
within an Interconnection.

R7.

N/A

N/A

The responsible entity, as
determinedidentified in
Requirement R1, identified
Contingencies for performing
Extreme Temperature
Assessment for each of the
planning eventscategory in
Table 1 that are expected to
produce more severe System
impacts withinon its planning
areaportion of the Bulk Electric
System, but did not include
the rationale for those
Contingencies selected for

The responsible entity, as
determinedidentified in
Requirement R1, did not
identify Contingencies for
performing Extreme
Temperature Assessment for
each of the planning
eventscategory in Table 1 that
are expected to produce more
severe System impacts
withinon its planning
areaportion of the Bulk Electric
System.

Draft 23 of TPL-008-1
JulyOctober 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

evaluation as supporting
documentationinformation.
R8.

The responsible entity, as
determinedidentified in
Requirement R1, completed
ansteady state and transient
stability analyses in the
Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but it was
performed less thanfailed to
document the assumptions for
one or equal to six months
late. more sensitivity cases in
accordance with Requirement
R8.

The responsible entity, as
determinedidentified in
Requirement R1, completed
ansteady state and transient
stability analyses in the
Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but it was
performed failed to document
the assumptions for one or
more than six months but less
than or equal to 12 months
late. benchmark planning
cases in accordance with
Requirement R8.

The responsible entity, as
determinedidentified in
Requirement R1, completed
ansteady state and transient
stability analyses in the
Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but it was
performed failed to evaluate
and document results for one
or more than 12 months but
less than or equal to 18
months late.of the sensitivity
cases in accordance with
Requirement R8.

The responsible entity, as
determinedidentified in
Requirement R1, performed
an completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but it was
more than 18 months late.
failed to evaluate and
document results for one or
more of the benchmark
planning cases in accordance
with Requirement R8.
OR
The responsible entity, as
determinedidentified in
Requirement R1, did not
perform anfailed to complete
steady state or transient
stability analyses and
document results in the
Extreme Temperature
Assessment.
OR
The responsible entity, as
determined using the
Contingencies identified in
Requirement R1, performed

Draft 23 of TPL-008-1
JulyOctober 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

an Extreme Temperature
Assessment, but it was missing
one or more of the required
elementsR7, in accordance
with Requirement R8.

R9.

N/A

N/A

The responsible entity, as
determinedidentified in
Requirement R1, developed a
Corrective Action Plan meeting
each of the elements inin
accordance with Requirement
R9, but failed to make theirits
Corrective Action Plan
available to, or solicit feedback
from, applicable regulatory
authorities or governing
bodies responsible for retail
electric service issues.

The responsible entity, as
determinedidentified in
Requirement R1, failed to
develop a Corrective Action
Plan meeting each of the
elements of Requirement R9
when the benchmark planning
case study results indicate the
System is unable to meet
performance requirements for
the Table 1 P0 or P1
Contingencies.
OR
The responsible entity, as
identified in Requirement R1,
developed a Corrective Action
Plan, but it was missing one or
more of the elements of
Requirement R9 Part 9.2-9.4
(as applicable).

R10.

N/A

Draft 23 of TPL-008-1
JulyOctober 2024

N/A

N/AThe responsible entity, as
identified in Requirement R1,
evaluated and documented
possible actions to reduce the
likelihood or mitigate the

EachThe responsible entity, as
determinedidentified in
Requirement R1, failed to
evaluateevaluated and
documentdocumented

Page 23 of 29

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

consequences and adverse
impacts of the event(s) when
analyses conclude there could
be instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Part 10.1,
but failed to evaluate and
document possible actions
where required under
Requirement R10 Part 10.2.

possible actions, to reduce the
likelihood or mitigate the
consequences, and adverse
impacts of the event(s) when
the benchmark planning case
study results indicate the
Systemanalyses conclude
there could result inbe
instability, uncontrolled
separation, or Cascading
forwithin an Interconnection
where required under
Requirement R10 Part 10.2,
but failed to evaluate and
document possible actions
where required under
Requirement R10 Part 10.1.
OR
The responsible entity, as
identified in Requirement R1,
failed to evaluate and
document possible actions to
reduce the Table 1 P2, P4, and
P7 Contingencieslikelihood or
mitigate the consequences
and adverse impacts of the
event(s) when analyses
conclude there could be
instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under

Draft 23 of TPL-008-1
JulyOctober 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Requirement R10 Parts 10.1
and 10.2.
R11.

The responsible entity, as
determinedidentified in
Requirement R1,
distributedprovided its
Extreme Temperature
Assessment results to
functional entities having a
reliability related need who
requested the information in
writing, but it was more than
60 days but less than or equal
to 80 days following the
request.

The responsible entity, as
determinedidentified in
Requirement R1,
distributedprovided its
Extreme Temperature
Assessment results to
functional entities having a
reliability related need who
requested the information in
writing, but it was more than
80 days but less than or equal
to 100 days following the
request.

The responsible entity, as
determinedidentified in
Requirement R1,
distributedprovided its
Extreme Temperature
Assessment results to
functional entities having a
reliability related need who
requested the information in
writing, but it was more than
100 days but less than or equal
to 120 days following the
request.

The responsible entity, as
determinedidentified in
Requirement R1,
distributedprovided its
Extreme Temperature
Assessment results to
functional entities having a
reliability related need who
requested the information in
writing, but it was more than
120 days following the
request.
OR
The responsible entity, as
determinedidentified in
Requirement R1, did not
distributeprovide its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requestedsubmitted
a written request for the
information in writing.

D. Regional Variances
None.

E. Associated Documents
Draft 23 of TPL-008-1
JulyOctober 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

•

Implementation Plan for Project 2023-07

•

Technical Rationale Document

•

Consideration of Issues and Directives for FERC Order 896.

Draft 23 of TPL-008-1
JulyOctober 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Version History
Version
1

Draft 23 of TPL-008-1
JulyOctober 2024

Date
TBD

Action

Change
Tracking

Addressing FERC Order 896

New Standard

Page 27 of 29

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature EventsTPL-008-

1 Supplemental Material

Attachment 1: Extreme Temperature Assessment Zones

The table below lists the zones to be used in the Extreme Temperature Assessment and
identifies the Planning Coordinators that belong to each zone. In accordance with Requirement
R2, each Planning Coordinator is required to identify the zone(s) to which it belongs.
Zone
MISO
SPP
PJM
NPCC (New England)
NPCC (New York)
SERC
SERC (Florida)
Central Canada
Eastern Canada
WECC Southwest
Pacific Northwest
Great Basin
Rocky Mountain
California/Mexico
Western Canada
ERCOT
Quebec

Draft 23 of TPL-008-1
JulyOctober 2024

Planning Coordinators

Eastern Interconnection
MISO
SPP
PJM
Planning Coordinators in NPCC that primarily
serve the six New England States
Planning Coordinators in NPCC that primarily
serve New York
Planning Coordinators in SERC excluding those
that primarily serve Florida and those in MISO,
SPP, or PJM
Planning Coordinators in SERC that primarily
serve Florida
Planning Coordinators that primarily serve
Saskatchewan and/or Manitoba region of MRO
Planning Coordinators in NPCC that primarily
serve Ontario, New Brunswick, and Nova Scotia
Western Interconnection
Planning Coordinators in the Southwest region of
WECC, including El Paso in West Texas
Planning Coordinators in the Pacific Northwest
region of WECC
Planning Coordinators in the Great Basin region
of WECC
Planning Coordinators in the Rocky Mountain
region of WECC
Planning Coordinators in the California/Mexico
region of WECC
Planning Coordinators that primarily serve British
Columbia and/or Alberta region of WECC
ERCOT Interconnection
Areas in Texas subject to ERCOTs jurisdiction.
Quebec Interconnection
Planning Coordinators that primarily serve
Quebec in the NPCC Region.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature EventsTPL-008-

1 Supplemental Material

The map below depicts an approximation of the zones to be used in the Extreme Temperature
Assessment and is provided as a visual aid; to the extent that there is a conflict between the
map and the table, the table controls. This map is not to be used for compliance purposes.

Draft 23 of TPL-008-1
JulyOctober 2024

Page 29 of 29

Implementation Plan

Project 2023-07 Transmission System Planning Performance
Requirements for Extreme Weather
Reliability Standard TPL-008-1
Applicable Standard
•

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature
Events

Requested Retirement
•

Not applicable

Prerequisite Standard
•

Not applicable

Applicable Entities
•

Planning Coordinators

•

Transmission Planners

New Term in the NERC Glossary of Terms

This section includes all newly defined, revised, or retired terms used or eliminated in the NERC Reliability
Standard. New or revised definitions listed below become approved when the proposed standard is
approved. When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
•

Extreme Temperature Assessment – Documented evaluation of future Bulk Electric System
performance for extreme heat and extreme cold benchmark temperature events.

Background

On June 15, 2023, the U.S. Federal Energy Regulatory Commission (“FERC”) issued Order No. 896, a final
rule directing NERC to develop a new or modified Reliability Standard to address the lack of a long-term
planning requirement(s) for extreme heat and cold weather events. 1 Specifically, FERC directed NERC to
develop modifications to Reliability Standard TPL-001-5.1 or develop a new Reliability Standard that
requires the following: (1) development of benchmark planning cases based on major prior extreme heat
and cold weather events and/or meteorological projections; (2) planning for extreme heat and cold weather
1

Transmission System Planning Requirements for Extreme Weather, Order No. 896, 183 FERC ¶ 61,191 (2023).

RELIABILITY | RESILIENCE | SECURITY

events using steady state and transient stability analyses expanded to cover a range of extreme weather
scenarios including the expected resource mix’s availability during extreme heat and cold weather
conditions, and including the wide-area impacts of extreme heat and cold weather; and (3) development
of Corrective Action Plans that mitigate any instances where performance requirements for extreme heat
and cold weather events are not met. FERC further directed NERC to ensure that the proposed new or
modified Reliability Standard becomes mandatory and enforceable beginning no later than 12 months from
the effective date of FERC approval.

General Considerations

Proposed Reliability Standard TPL-008-1 would require the performance of an Extreme Temperature
Assessment at least once every five calendar years (Requirement R1). This implementation plan provides a
staggered approach for the performance of the first Extreme Temperature Assessment, with phased-in
compliance dates beginning 12 months from the effective date of regulatory approval consistent with Order
No. 896. For subsequent Extreme Temperature Assessments, entities may establish timeframes appropriate
to their facts and circumstances for carrying out their responsibilities under the standard, provided that the
Extreme Temperature Assessment is completed no later than five calendar years following the previous
Extreme Temperature Assessment.

Effective Date

The effective date for the proposed Reliability Standard is provided below. Where the standard drafting
team identified the need for a longer implementation period for compliance with a particular section of the
proposed Reliability Standard (e.g., an entire Requirement or a portion thereof), the additional time for
compliance with that section is specified below. These phased-in compliance dates represent the dates that
entities must begin to comply with that particular section of the Reliability Standard, even where the
Reliability Standard goes into effect at an earlier date.
TPL-008-1 and Definition

Where approval by an applicable governmental authority is required, the standard and definition of
Extreme Temperature Assessment shall become effective on the first day of the first calendar quarter that
is twelve (12) 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 twelve (12) months after the date the standard
and definition of Extreme Temperature Assessment is adopted by the NERC Board of Trustees, or as
otherwise provided for in that jurisdiction.

Phased-In Compliance Dates

Compliance Date for TPL-008-1 Requirement R1

Entities shall be required to comply with Requirement R1, pertaining to the identification of individual and
joint responsibilities for completing the Extreme Temperature Assessment, upon the effective date of
Reliability Standard TPL-008-1.

Implementation Plan
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | October 2024

2

Compliance Date for TPL-008-1 Requirements R2, R3, R4, R5, R6

Entities shall not be required to comply with Requirements R2, R3, R4, R5, and R6 until twenty-four (24)
months after the effective date of Reliability Standard TPL-008-1.
Compliance Date for TPL-008-1 Requirements R7, R8, R9, R10, R11

Entities shall not be required to comply with Requirements R7, R8, R9, R10, R11 until forty-eight (48) months
after the effective date of Reliability Standard TPL-008-1.
Figure 1: Implementation Plan, Demonstrating Effective Date
and Phased-in Compliance Dates from Regulatory Approval

Initial Performance of Periodic Requirements

Entities shall complete the Extreme Temperature Assessment no later than forty-eight (48) months after
the effective date of Reliability Standard TPL-008-1. Subsequent Extreme Temperature Assessments shall
be completed by no later than five calendar years following the completion of the previous Extreme
Temperature Assessment.

Implementation Plan
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | October 2024

3

Technical Rationale and
Justification for TPL-008-1

Project 2023-07 Transmission Planning
Performance Requirements for Extreme
Weather
October 2024

RELIABILITY | RESILIENCE | SECURITY

NERC | Report Title | Report Date
I

Table of Contents
Preface ........................................................................................................................................................................... iii
Introduction ................................................................................................................................................................... iv
Defined Terms ................................................................................................................................................................. 5
TPL-008-1 Standard ......................................................................................................................................................... 6
Requirement R1 .............................................................................................................................................................. 7
Requirement R2 .............................................................................................................................................................. 8
Requirement R3 ............................................................................................................................................................ 10
Requirement R4 ............................................................................................................................................................ 11
Requirement R5 ............................................................................................................................................................ 12
Requirement R6 ............................................................................................................................................................ 13
Requirement R7 ............................................................................................................................................................ 14
Requirement R8 ............................................................................................................................................................ 17
Requirement R9 ............................................................................................................................................................ 19
Requirement R10 .......................................................................................................................................................... 20
Requirement R11 .......................................................................................................................................................... 21

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ii

Preface
Electricity is a key component of the fabric of modern society and the Electric Reliability Organization (ERO) Enterprise
serves to strengthen that fabric. The vision for the ERO Enterprise, which is comprised of NERC and the six Regional
Entities, is a highly reliable, resilient, and secure North American bulk power system (BPS). Our mission is to assure
the effective and efficient reduction of risks to the reliability and security of the grid.
Reliability | Resilience | Security
Because nearly 400 million citizens in North America are counting on us
The North American BPS is made up of six Regional Entities as shown on the map and in the corresponding table
below. The multicolored area denotes overlap as some load-serving entities participate in one Regional Entity while
associated Transmission Owners/Operators participate in another.

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

Texas RE

Texas Reliability Entity

WECC

WECC

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iii

Introduction
This document explains the technical rationale and justification for the proposed Reliability Standard TPL-008-1. It
provides stakeholders and the ERO Enterprise with an understanding of the technology and technical requirements
in the Reliability Standard. This Technical Rationale and Justification for TPL-008-1 is not a Reliability Standard and
should not be considered mandatory and enforceable.

Background

On June 15, 2023, FERC issued FERC Order No. 896 that acknowledges the “challenges associated with planning for
extreme heat and cold weather events, particularly those that occur during periods when the Bulk-Power System
must meet unexpectedly high demand. Extreme heat and cold weather events have occurred with greater frequency
in recent years and are projected to occur with even greater frequency in the future. These events have shown that
load shed during extreme temperatures result in unacceptable risk to life and have extreme economic impact. As
such, the impact of concurrent failures of Bulk-Power System generation and transmission equipment and the
potential for cascading outages that may be caused by extreme heat and cold weather events should be studied and
corrective actions should be identified and implemented.” 1
Therefore, the Commission directed in FERC Order No. 896 to develop a new or modified Reliability Standard to
address a lack of long-term planning requirement(s) for extreme heat and cold weather events. Specifically, FERC
directed NERC to develop modifications to Reliability Standard TPL-001-5.1 or a new Reliability Standard, to require
the following: (1) development of benchmark planning cases based on major prior extreme heat and cold weather
events and/or meteorological projections; (2) planning for extreme heat and cold weather events using steady state
and transient stability analyses expanded to cover a range of extreme weather scenarios including the expected
resource mix's availability during extreme heat and cold weather conditions, and including the wide-area impacts of
extreme heat and cold weather; and (3) development of corrective action plans that mitigate any instances where
performance requirements for extreme heat and cold weather events are not met.

1

N. Am. Elec. Reliability Corp., 183 FERC ¶ 61,191 (2023) (FERC Order), Final Rule. eLibrary | File List (ferc.gov)
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iv

Defined Terms
The Standard Drafting Team (SDT) defined one term to be added to the NERC Glossary of Terms to make the
requirements easier to read and understand.
Extreme Temperature Assessment
Documented evaluation of future Bulk Electric System performance for extreme heat and extreme cold
benchmark temperature events.
The definition of Extreme Temperature Assessment was developed by the SDT to limit wordiness throughout the
requirements.

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TPL-008-1 Standard
The FERC Order No. 896 directed NERC to submit a new Reliability Standard or modifications to Reliability Standard
TPL-001-5.1 to address the concerns pertaining to transmission system planning for extreme heat and cold weather
events that impact the Reliable Operation of the Bulk-Power System.
The SDT determined that a new Reliability Standard was the cleanest way to address FERC’s directives versus
modifying Reliability Standard TPL-001-5.1. While the TPL-008-1 standard uses similar requirements, this allows
industry to have one standard that focuses on extreme heat and extreme cold benchmark temperature events.
The purpose of TPL-008-1 is to “Establish Transmission system planning performance requirements to develop a Bulk
Power System (BPS) that will operate reliably during extreme heat and extreme cold temperature events.” The
directives in FERC Order No. 896 pertain to the reliable operation of the BPS, and the requirements of TPL-008-1
support that by ensuring Planning Coordinators and Transmission Planners are planning their portions of the Bulk
Electric System to meet performance requirements in extreme heat and extreme cold benchmark temperature
events.

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Requirement R1
Requirement R1 requires each Planning Coordinator (PC) and the Transmission Planner(s) (TP) within the PC’s
footprint to identify each entity’s individual and joint responsibilities when completing the Extreme Temperature
Assessment at least once every five calendar years. The purpose of this requirement is to have the PC and its TP(s)
identify their individual and joint responsibilities for the following activities:
•

Identifying the PC’s zone(s) and coordinating with all PCs in each of its identified zone(s) to select one
common extreme heat benchmark temperature event and one common extreme cold benchmark
temperature event (Requirement R2),

•

Implementing a process for developing benchmark planning cases and sensitivity cases (Requirement R3),

•

Developing benchmark planning cases and sensitivity cases (Requirement R4),

•

Having acceptable criteria (Requirements R5 and R6),

•

Identifying Contingencies for evaluation (Requirement R7),

•

Performing steady state and transient stability analyses (Requirement R8),

•

Developing Corrective Action Plans when required (Requirement R9),

•

Evaluating and documenting possible actions for performance deficiencies that do not require Corrective
Action Plans (Requirement R10), and

•

Providing study results to any functional entity that has a reliability related need (Requirement R11).

The responsibilities described in Requirements R2 and R3 are explicitly assigned to the PC. The responsibilities
described in Requirements R4 through R11 may be completed by either the PC or one or more of its TPs. Requirement
R1 requires that an agreement is reached on the individual and joint responsibilities for completing the Extreme
Temperature Assessment between the PC and its TPs.

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Requirement R2
Requirement R2 requires each Planning Coordinator (PC) to identify the zone(s) it will participate in for the
components of the Extreme Temperature Assessment that require coordination. PCs in the same zone are required
to coordinate to:
•

Select one common extreme heat benchmark temperature event and one common extreme cold benchmark
temperature event (Requirement R2), and

•

Implement a process for developing benchmarking planning cases and sensitivity cases (Requirement R3).

FERC Order No. 896 directed NERC to require that transmission planning studies under the new or revised Reliability
Standard consider the wide-area impacts of extreme heat and cold weather. NERC already defines “Wide Area” as
“The entire Reliability Coordinator Area as well as the critical flow and status information from adjacent Reliability
Coordinator Areas as determined by detailed system studies to allow the calculation of Interconnected Reliability
Operating Limits.” Reliability Coordinator Areas can be geographically very large – for example the Reliability
Coordinator West (RCW) region extends from the Pacific Northwest to the southern borders of California and Arizona.
Thus, defining coordination requirements based on these boundaries may not accurately capture weather events and
system impacts at a sufficiently granular level. In addition, it is recognized that electrical boundaries such as those
defining the Eastern/Western/ERCOT interconnections limit the potential for events in one area to affect reliability
in another.
Considering the above, the SDT identified the zones depicted in Attachment 1 as reasonable boundaries that balance
the need for studies to cover large regions with similar weather patterns with the need for a manageable level of
coordination. An earlier proposal to limit coordination to only adjacent PCs was not adequate for meeting FERC’s
directives. While the zones depicted in Attachment 1 will require some PCs to coordinate with many other PCs, the
industry has demonstrated, through various working groups and organizations, that it is capable of cooperating to
build models that represent large areas.
Requirement R2 describes the need to select extreme benchmark temperature events necessary for the creation of
benchmark planning cases. Specifically, extreme hot and cold temperatures experienced during benchmark events
are assumed to be outside the ranges used as the basis of planning cases studied under Reliability Standard TPL-0015.1. Since temperature levels and associated weather conditions affect load levels, generation performance, and
transfer levels, the selection of benchmark events is critical to ensuring the Extreme Temperature Assessment
appropriately evaluates probable System conditions.
Since any region can experience temperatures that are higher or lower than normal, PCs within the same zone must
coordinate to select one common temperature event that includes hotter temperature assumptions and one
common temperature event that includes colder temperature assumptions. While it is understood that, for example,
one region may typically experience hotter summers and milder winters than another region, both a hotter than
average summer and a colder than average winter could result in reliability concerns. Therefore, the requirement is
for one common case specific to extreme heat and one common case specific to extreme cold conditions to be studied
for the Extreme Temperature Assessment. By selecting the same, common events, PCs ensure that extreme
temperatures are studied over the entire zone. The evaluation of a common event taking place over a wide area is
foundational to FERC Order No. 896. Furthermore, selecting the same, common events reasonably limits coordination
requirements. PCs are required to participate in the selection of events for their zone(s), but have no responsibilities
for the selection of events in other zones.
The SDT determined that the extreme heat and extreme cold temperatures selected must have a verified statistical
basis based on weather data from credible sources. The SDT has identified several key features that are used to
NERC | Technical Rationale and Justification for TPL-008-1 | October 2024
8

Requirement R2

determine when a temperature event will constitute a valid extreme benchmark temperature event for the purposes
of completing the Extreme Temperature Assessment. Specifically, extreme benchmark temperature events must:
•

Consider no less than 40 years of temperature data,

•

Utilize data ending no more than 5 years prior to the time benchmark temperature events are selected, and

•

Represent one of the worst 20 extreme temperature conditions within the zone.

Temperature events are ranked by computing the 3-day rolling average of daily maximum temperatures (for extreme
heat) or daily minimum temperatures (for extreme cold). The ERO will maintain a library of benchmark events to
provide responsible entities access to vetted benchmark temperature events that meet the criteria of Requirement
R2. While selection of events from the ERO’s provided library assures entities they are selecting valid events,
Requirement R2 does not preclude entities from collecting temperature data and identifying benchmark temperature
events through their own process. Entities that elect to develop their own benchmark temperature events are
responsible for ensuring the input temperature data and selected benchmark temperature events meet the criteria
of Requirement R2. Additionally, because Requirement R2 requires PCs within a zone to coordinate in the selection
of the benchmark temperature events, the process used to identify these events must be agreeable to those PCs.
The requirement to consider no less than 40 years of temperature data was established based on the observation
that many of the worst events identified in various regions of North America occurred in the 1980s and 1990s. For
example, preliminary data indicated that the five worst extreme cold temperature events in the PJM region over the
last 43 years occurred between 1983 and 1994. Similar results were seen in other regions for both extreme heat and
extreme cold temperature events. Thus, the SDT determined that a minimum of 40 years of temperature data should
be used to ensure more extreme events weren’t excluded by using a shorter duration of temperature data.

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Requirement R3
Requirement R3 aligns with directives in FERC Order No. 896, emphasizing the importance of coordinating the
development of benchmark planning cases and sensitivity cases amongst PCs within a zone, where the scope of
extreme temperature event studies will likely cover large geographical areas exceeding smaller individual planning
areas. The SDT considered comments from the industry expressing concerns regarding the necessity to coordinate
among all impacted PCs in developing benchmark planning cases and sensitivity cases for various extreme benchmark
temperature events. Recognizing that coordination among all impacted PCs may not be necessary to ensure reliability
within an individual planning area, the SDT drafted Requirement R3 to require each PC to coordinate with all PCs
within a zone to implement a process for the development of benchmark planning cases and sensitivity cases. The
SDT believes this change balances the need to ensure the planning cases capture impacts to/from entities affected
by the same benchmark temperature event, while recognizing that reliability will be less impacted by system changes
far removed from the zone.
PCs within a zone must coordinate to implement a process that results in the development of benchmark planning
cases that represent the benchmark temperature events selected in accordance with Requirement R2, and sensitivity
cases that demonstrate the impact of changes to the basic assumptions used in the benchmark planning cases. This
process requires several components, outlined in the sub-requirements of Requirement R3.
First, Requirement R3 Part 3.1 requires PCs within a zone to identify System models form the basis for developing the
benchmark planning cases. These models must represent one of the years in the Long-Term Transmission Planning
Horizon. PCs will also need to ensure models include stability modeling data to provide for the performance of
stability analysis later in the process. It is reasonable anticipated that PCs will likely utilize a summer peak model as
the starting point for the extreme heat benchmark temperature event and a winter peak model as the starting point
for the extreme cold benchmark temperature event.
Secondly, Requirement R3 Part 3.2 requires that PCs within a zone provide forecasted data for their area within the
zone that represents the benchmark temperature events selected in accordance with Requirement R2. Each PC must
provide data for their area within the zone that represents seasonal and temperature adjustments for Load,
generation, Transmission, and transfers. The provided data should be used to update the starting point models to
reflect the selected benchmark temperature events.
Thirdly, Requirement R3 Part 3.3 allows PCs to agree on assumptions for seasonal and temperature adjustments for
Load, generation, Transmission, and transfers in areas outside of the zone. As a sub-requirement of Requirement R3,
these assumptions must be coordinated among PCs in the zone, as needed. As an example, PCs within the zone may
identify the need for imported power during a benchmark event. The PCs may evaluate historical import availability
and assume an import from an area outside of the zone is reasonable and should be modeled.
Finally, Requirement R3 Part 3.4 requires PCs to coordinate and identify changes to generation, real and reactive
forecasted Load, or transfers that should be reflected in sensitivity cases. Sensitivity cases are intended to
demonstrate the impact of changes to the basic assumptions used in the benchmark planning cases, and Requirement
R3 Part 3.4 ensures PCs are cooperating to identify changes that sufficiently alter the assumptions reflected in the
benchmark planning cases. For example, PCs that identified an import external source to the zone for a benchmark
planning case may elect to alter the source of that import in the sensitivity case.

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Requirement R4
The SDT drafted Requirement R4 to require the responsible entity to use data consistent with Reliability Standard
MOD-032, supplemented by other sources as needed, for developing benchmark planning cases that represent
System conditions based on selected benchmark temperature events. This aligns with directives in FERC Order No.
896, paragraph 30, emphasizing the requirement of developing both benchmark planning cases and sensitivity study
cases. Requirement R4 is consistent with Reliability Standard TPL-001-5.1 in cross-referencing Reliability Standard
MOD-032, which establishes consistent modeling data requirements and reporting procedures for the development
of planning horizon cases necessary to support analysis of the reliability of the interconnected System. It is also
consistent with Reliability Standard TPL-001-5.1 in acknowledging that data from other sources may be required to
supplement the data collected through Reliability Standard MOD-032 procedures.
Requirement R4 requires entities to use the coordination process developed in accordance with Requirement R3 to
develop the following four cases:
•

One common extreme heat benchmark planning case (Requirement R4 Part 4.1),

•

One common extreme cold benchmark planning case (Requirement R4 Part 4.1),

•

One common extreme heat sensitivity case (Requirement R4 Part 4.2), and

•

One common extreme cold sensitivity case (Requirement R4 Part 4.2).

At the completion of the case development process implemented in accordance with Requirement R3, and executed
in Requirement R4, responsible entities will have the four cases listed above. This establishes category P0 as the
normal System condition in Table 1 for each case. Requirement R3 does not preclude PCs from implementing a
process that develops cases for multiple benchmark temperature events or additional sensitivity cases. Moreover,
entities may elect to develop additional cases for their internal use.
As per FERC Order No. 896, paragraph 94, it is clarified that resource adequacy benchmarks are not within the scope
of TPL-008-1. The intent of the standard is to evaluate benchmark events where sufficient generation is available to
supply load. However, under an extreme heat or extreme cold temperature condition, there may be instances where
the benchmark planning cases and/or sensitivity cases may not have sufficient available generation to supply the
load. In these scenarios, it may be acceptable for the responsible entity to revise the model to reduce the forecasted
Load, or include forecasted generation, to achieve a solution for the benchmark planning cases and/or sensitivity
cases and evaluate future Bulk Electric System performance for extreme temperature events. Each responsible entity,
as identified in Requirement R1, shall have dated evidence in either electronic or hard copy format that it developed
benchmark planning cases and sensitivity cases in accordance with Requirement R4.

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Requirement R5
Requirement R5 was drafted to require each responsible entity to set the criteria needed for limits that will be used
to evaluate System steady state voltage and post-Contingency voltage deviations for completing the Extreme
Temperature Assessment. The establishment of these criteria allows auditors to compare the results of the Extreme
Temperature Assessment with the established criteria.

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Requirement R6
Requirement R6 was drafted to require the responsible entity to define and document the criteria or methodology
used in evaluating the Extreme Temperature Assessment analysis to identify instability, uncontrolled separation, or
Cascading within an Interconnection. Adequate and thorough criteria should be built into the Extreme Temperature
Assessment to help identify instability, uncontrolled separation, and Cascading conditions. The establishment of
these criteria allows auditors to compare the results of the Extreme Temperature Assessment with the established
criteria.

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Requirement R7
This requirement addresses directives in FERC Order No. 896 to define a set of Contingencies that responsible entities
will be required to consider when conducting wide-area studies of extreme heat and cold weather events. FERC’s
preference to rely on established Contingency definitions, “[w]e believe that it is necessary to establish a set of
common contingencies for all responsible entities to analyze. Required contingencies, such as those listed in Table 1
of Reliability Standard TPL-001-5.1 (i.e., category P1 through P7), establish common planning events that set the
starting point for transmission system planning assessments,” was also considered by the SDT. It is necessary to
establish a set of common Contingencies for all responsible entities to analyze. Requiring the study of predefined
Contingencies, such as those listed in Table 1, will ensure a level of uniformity across planning regions, considering
that extreme heat and cold weather events often exceed the geographic boundaries of most existing planning
footprints. Defining the Contingencies in Table 1 consistently with Table 1 of Reliability Standard TPL-001-5.1 meets
FERC’s preference for commonality.
If feasible, all Contingencies listed in Table 1 should be considered for evaluation by the responsible entity; however,
the language affords flexibility in identifying the most appropriate Contingencies. As such, the responsible entity
should implement a method and establish sufficient supporting rationale to ensure Contingencies within each
category of Table 1 that are expected to produce more severe System impacts within its planning area are adequately
identified. It is noted that since the benchmark planning cases are developed from the extreme temperature
benchmark events, they already represent extreme System conditions and thus not all Contingencies from Reliability
Standard TPL-001-5.1 Table 1 are included in the TPL-008-1 Table 1 for assessment. The Events included in TPL-0081 Table 1 represent the more likely Contingencies to occur.
The SDT included categories P0, P1, and P7 in Table 1 of TPL-008-1. The SDT finds it reasonable to exclude P2, P3, P4,
P5 and P6 Contingencies from the Extreme Temperature Assessment. Studying categories P0, P1 and P7 is the
minimum requirement of TPL-008-1. The standard does not preclude entities from studying additional Contingencies
if desired. The following discusses the rationale for excluding P2 through P6 Contingencies for TPL-008-1:
1. Excluding P2 and P4 Contingencies:
After consideration of comments received from the industry, the SDT removed P2 and P4 Contingencies due
to lower probability of occurrence than P1 and P7 Contingencies. The standard establishes minimum
requirement for Contingencies with higher probability of occurrence. To the extent that the responsible
entity determines the need for studying beyond the minimum requirements, the standard does not preclude
the entity from doing so.
2. Excluding P3 and P6 Contingencies:
Part of the decision stems from the complexity of P3 and P6 Contingencies, which involve multiple element
outages triggered by multiple Contingencies, with System adjustments allowed between them.
Consequently, the occurrence likelihood of P3 and P6 Contingencies could be even lower compared to P1
and P7 Contingencies. Moreover, aligning with the directives set forth in FERC Order 896, which emphasizes
the importance of incorporating derated generation, transmission capacity, and the availability of generation
and transmission in the development of benchmark planning cases, it becomes imperative for responsible
entities to consider potential concurrent or correlated generation and transmission outages and/or derates
within relevant benchmark planning cases. This ensures that the benchmark planning case accurately reflects
System conditions under extreme temperatures, with generation and transmission derates and/or outages
already factored. Therefore, the SDT believes excluding P3 and P6 is justified, as generation and transmission
derates and/or outages are already accounted for within the benchmark planning cases.
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3. Excluding P5 Contingencies:
After consideration of comments were received, the SDT removed P5 Contingency (Delayed Fault Clearing
due to failure of non-redundant component of a Protection System). This is because while some categories
of Contingencies may be assessed in a straightforward approach, category P5 Contingency events often
require a significant level of engineering analysis (including protection and/or control analysis). These
analyses are sensitive to the System topology and expected dispatch. As the planning benchmark cases are
developed for TPL-008-1 that represent System conditions that are different than the typical summer or
winter peak conditions, the development of category P5 Contingency events is expected to be a significant
burden. Since these events only require evaluations of possible mitigations (and not Corrective Action Plans),
violations resulting from these events are unlikely to result in significant transmission System investment.
Furthermore, any violations resulting from category P5 events may be mitigated by eliminating and
addressing the single point of failure included in the event definition. Thus, the evaluation of possible actions
is unlikely to result in further insight beyond the general reliability improvements associated with eliminating
single points of failure.
The SDT discussed and decided to keep the P7 Contingency category because common structure Contingencies are
often evaluated after categories P0 and P1 as the most common minimum level of transmission reliability assessment.
These events have a high likelihood of occurrence due to the following reasons:
•

Historical events that include simultaneous forced outage due to tripping of the double-circuit power lines
due to electrical storms events;

•

Environment-caused factors include pollution buildup such as dust that could cause faulted condition that
trips both transmission lines on a common tower;

•

Avian-caused outages that impact both transmission lines on a common tower;

•

Smoke from nearby wildfires can cause simultaneous tripping of both circuits on a common tower;

•

Nearby wildfires can impact System Operation as System Operators proactively de-energize both lines on a
common tower to avoid further impact to the transmission grid in the event of a simultaneous tripping of
both lines that may be carrying high power transfer between areas;

•

Weather-related causes such as lightning, flooding, wind, icing can cause tripping of both transmission lines
on a common tower;

•

Natural disaster such as winter storm can cause transmission tower to collapse, taking out both lines strung
on the same tower;

•

Other incidents such as vehicle accident, aircraft accident, vandalism, animal contact can adversely impact
both transmission lines on the common tower.

•

Loss of two circuits running in parallel simultaneously is likely to have a greater system impact versus loss of
two unrelated or geographically separated circuits. Therefore, there is greater potential for reliability
concerns, especially during heavy transfers that are likely during periods of extreme weather, due to loss of
a both circuits of a double-circuit line.

•

Due to the reasons above, Contingencies that involve double-line circuits on a common tower are mostly
included in the critical multiple Contingency list in System Operations reliability assessment.

Some, but not all, items to consider when developing the rationale for selecting Contingencies are:
• Past studies,
• Subject matter expert knowledge of the responsible entity’s System (to be supplemented with data or
analysis), and
• Historical data from past operating events.
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Requirement R8
Requirement R8 was drafted to provide clarity on the following:
1. What planning study cases are required?
The Requirement R8 includes the following number of assessments to complete the Extreme Temperature
Assessment and address FERC Order No. 896 directives per paragraph 111 that “direct NERC to require in
the proposed new or modified Reliability Standard that responsible entities perform both steady state and
transient stability (dynamic) analyses in the extreme heat and cold weather planning studies”. In addition,
Requirement R8 also addresses FERC Order No. 896 directives per paragraph 124 that “require the use of
sensitivity cases to demonstrate the impact of changes to the assumptions used in the benchmark planning
case”. Requirement R8 also addresses FERC Order No. 896 directives per paragraph 124 that sensitivity
cases “should consider including conditions that vary with temperature such as load, generation, and
system transfers.” Since the benchmark planning case(s) already include System conditions under extreme
heat or extreme cold events, the sensitivity analysis is to include changes to at least one of the following
conditions: generation, real and reactive forecasted Load, or transfers. Since the minimum requirement
includes changes to one of these conditions, the PCs and the TPs can include further sensitivity assessments
to change more conditions if they choose to do so.
The following provides the number of assessments required for the benchmark planning and sensitivity
cases to complete the Extreme Temperature Assessment.
Type of Extreme
Temperature
Assessment

Extreme Cold Temperature
Event

Extreme Heat
Temperature Event

Total

Benchmark Planning
Case Analysis

One extreme cold
benchmark planning case
assessment

One extreme heat
benchmark planning case
assessment

Two benchmark
planning case
assessments

Sensitivity Case
Analysis

One sensitivity case with
changes to at least one of
the following conditions:
generation, real and
reactive forecasted Load,
or transfers

One sensitivity case with
changes to at least one of
the following conditions:
generation, real and
reactive forecasted Load,
or transfers

Two sensitivity case
assessments

Total

A total of four
assessments to
complete the
Extreme
Temperature
Assessment

2. What are the types of analyses required?
There are two types of analyses required: steady-state and transient stability. Each type of analysis must be
completed for each of the four cases described in the table above. This requirement is to satisfy FERC Order
No. 896 directive paragraph 111.

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Requirement 7

Requirement R9
FERC Order No. 896 identifies a deficiency in the existing Reliability Standard TPL-001-5.1 where “planning
coordinators and transmission planners are required to evaluate possible actions to reduce the likelihood or mitigate
the consequences of extreme temperature events but are not obligated to develop corrective action plans” (¶139).
Given potential severe consequences of extreme cold and extreme heat events, FERC Order No. 896 raises the bar
and “directs NERC to require in the new or modified Reliability Standard the development of extreme weather
corrective action plans for specified instances when performance standards are not met” (¶152).
Due to higher likelihood of categories P0 and P1, these categories are held to a higher performance requirement in
benchmark planning cases. Corrective Action Plans are required to address performance deficiencies for categories
P0 and P1 in benchmark planning cases analyzed in the Extreme Temperature Assessment.
Furthermore, having a Corrective Action Plan requirement for categories P0 and P1 in benchmark planning cases
ensures resilience during future extreme cold and extreme heat temperature events, when the transmission System
is required to be P1 Contingency-secure (for steady-state and transient stability).
Given that a category P0 represents a continuous System condition without any system disturbances, the SDT
determined that load shedding should not be considered as a Corrective Action Plan. However, the SDT has
determined that load curtailment may be considered for a P1 Contingency as a Corrective Action Plan where load
shed is allowed to prevent system-wide failures and ensuring the continued operation of essential services under a
critical P1 Contingency in the extreme heat and cold temperature events. The SDT also emphasizes that alternative
solutions, other than firm load curtailment, are evaluated in higher priorities. Non-Consequential Load Loss is
permitted as an interim solution in situations that are beyond the control of the Planning Coordinator or Transmission
Planner that prevent the implementation of a Corrective Action Plan in the required timeframe; however, the
responsible entity must document the situation causing the problem, alternatives evaluated, and take actions to
resolve the situation. Future revisions to the Corrective Action Plan are allowed, provided that the planned Bulk
Electric System continues to meet the performance requirements of Table 1.
FERC Order No. 896 also directs NERC “to develop certain processes to facilitate interaction and coordination with
applicable regulatory authorities or governing bodies responsible for retail electric service as appropriate in
implementing a corrective action plan” (¶152). In the event that Non-Consequential Load Loss is included in the
Corrective Action Plan for a P1 Contingency, the responsible entity shall document alternative(s) considered, make
the Corrective Action Plan available to, and solicit feedback from, applicable regulatory authorities or governing
bodies responsible for retail electric service issues.

NERC | Technical Rationale and Justification for TPL-008-1 | October 2024
20

Requirement R10
The requirement for responsible entities to evaluate and document possible actions designed to reduce the likelihood
or mitigate the consequences and adverse impacts when the study results in the benchmark planning cases analyses
conclude there could be instability, uncontrolled separation, or Cascading for P7 Contingencies is in response to
directives outlined in FERC Order No. 896.
P7 Contingencies involve multiple element outages resulting from a single event, making them relatively less likely to
occur, compared to categories P0 and P1, but potentially causing more severe system impacts. Considering both the
likelihood of these Contingencies, and the fact that the Extreme Temperature Assessment already addresses lowprobability System conditions, the SDT determined that Corrective Action Plans should not be required for P7
Contingencies. However, due to the potential severity resulting from single-Contingency multiple element outages,
the SDT believes it is appropriate for responsible entities to at least evaluate and document possible mitigation
actions to reduce the likelihood or mitigate the consequences and adverse impacts of the event(s) when analyses
conclude there could be instability, uncontrolled separation, or Cascading. The biggest benefit from the evaluation
and documentation of the possible mitigating actions is it allows a responsible entity to see where major reliability
concerns exist that may need to be addressed; and, if a sufficiently large number of reliability concerns are identified,
it may encourage transmission upgrade mitigation option(s) to be considered and implemented without it being
strictly called for in the standard. Not requiring Corrective Action Plans for these Contingencies, but requiring the
evaluation, is a compromise from having Corrective Action Plans for all studied Contingencies.
Furthermore, FERC Order No. 896 requires “the use of sensitivity cases to demonstrate the impact of changes to the
assumptions used in the benchmark planning case” (¶124). FERC Order No. 896 also states: “NERC should determine
whether corrective action plans should be required for single or multiple sensitivity cases, and whether corrective
action plans should be developed if a contingency event that is not already included in benchmark planning case
would result in cascading outages, uncontrolled separation, or instability” (¶158). The SDT acknowledges that
sensitivity analysis is an important component of a robust transmission planning study. A requirement to develop
and implement Corrective Action Plans for sensitivity cases may incentivize responsible entities to select fewer or
less severe sensitivities. An incentive to select fewer sensitivities is undesirable because sensitivity study results are
used to identify constraints and initiate deeper analysis into the variables that impact those constraints. The study
results of sensitivity cases are also important to inform the development of Corrective Action Plans in the benchmark
planning cases. Therefore, the SDT determined the responsible entity must evaluate and document possible actions
designed to reduce the likelihood or mitigate the consequences and adverse impacts of the event(s) when analyses
of sensitivity cases conclude there could be instability, uncontrolled separation, or Cascading for categories P0, P1,
and P7. Finally, TPL-008-1 does not preclude the responsible entity from developing Corrective Action Plans for
sensitivity cases beyond what is required in the standard.

NERC | Technical Rationale and Justification for TPL-008-1 | October 2024
21

Requirement 7

Requirement R11
The requirement for responsible entities to share Extreme Temperature Assessment results aligns with directives in
FERC Order No. 896, emphasizing coordination and sharing of study findings. It ensures collaboration among
stakeholders and timely dissemination of critical information to entities with reliability-related needs. This fosters a
collective understanding of reliability concerns identified in wide-area studies, thereby enhancing overall grid
reliability.

NERC | Technical Rationale and Justification for TPL-008-1 | October 2024
22

Unofficial Comment Form

Project 2023-07 Transmission Planning Performance Requirements for
Extreme Weather
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on draft three of TPL-008-1 – Transmission System Planning Performance
Requirements for Extreme Temperature Events by 8 p.m. Eastern, October 21, 2024.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Senior Standards
Developer, Jordan Mallory (via email), or at 470-479-7538.
Background Information

On June 15, 2023, FERC issued FERC Order No. 896 that acknowledges the “challenges associated with
planning for extreme heat and cold weather events, particularly those that occur during periods when the
Bulk-Power System must meet unexpectedly high demand. Extreme heat and cold weather events have
occurred with greater frequency in recent years, and are projected to occur with even greater frequency
in the future. These events have shown that load shed during extreme temperature result in unacceptable
risk to life and have extreme economic impact. As such, the impact of concurrent failures of Bulk-Power
System generation and transmission equipment and the potential for cascading outages that may be
caused by extreme heat and cold weather events should be studied and corrective actions should be
identified and implemented.” 1
Therefore, the Commission directed, in FERC Order No. 896, to develop a new or modified Reliability
Standard to address a lack of long-term planning requirement(s) for extreme heat and cold weather
events. Specifically, FERC directed NERC to develop modifications to Reliability Standard TPL-001-5.1 or a
new Reliability Standard, to require the following: (1) development of benchmark planning cases based on
major prior extreme heat and cold weather events and/or meteorological projections; (2) planning for
extreme heat and cold weather events using steady state and transient stability analyses expanded to
cover a range of extreme weather scenarios including the expected resource mix's availability during
extreme heat and cold weather conditions, and including the wide-area impacts of extreme heat and cold
weather; and (3) development of corrective action plans that mitigate any instances where performance
requirements for extreme heat and cold weather events are not met.

1

N. Am. Elec. Reliability Corp., 183 FERC ¶ 61,191 (2023) (FERC Order), Final Rule. eLibrary | File List (ferc.gov)

RELIABILITY | RESILIENCE | SECURITY

Questions

1. Requirement R1 requires Planning Coordinators (PCs) to identify their zone in the map included
in Attachment 1. Do you agree with the zones identified on this map? If you do not agree, please
provide your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
2. The Drafting Team (DT) updated Requirement R2 based on comments received. Do you agree
with the updated proposed TPL-008-1 Reliability Standard Requirement? If you do not agree,
please provide your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
3. The DT updated Requirements R3 – R4 based on comments received. Do you agree with the
updated proposed TPL-008-1 Reliability Standard Requirements? If you do not agree, please
provide your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
4. The DT updated Requirements R7 – R8 based on comments received. Do you agree with the
updated proposed TPL-008-1 Reliability Standard Requirements? If you do not agree, please
provide your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
5. The DT updated Requirements R9 – R11 based on comments received. Do you agree with the
updated proposed TPL-008-1 Reliability Standard Requirements? If you do not agree, please
provide your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:

Unofficial Comment Form
Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather | October 2024

6. The DT believes proposed modifications in TPL-008-1 provide entities with flexibility to meet the
reliability objectives in a cost-effective manner. Do you agree? If you do not agree, or if you agree
but have suggestions for improvement to enable more cost-effective approaches, please provide
your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
7. Provide any additional comments for the drafting team to consider, including the provided
technical rationale document, if desired.
Comments:

Unofficial Comment Form
Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather | October 2024

Violation Risk Factor and Violation Severity Level
Justifications

Project 2023-07 Transmission System Planning Performance Requirements for
Extreme Weather
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 2023-07 Transmission System Planning Performance Requirements for Extreme Weather. 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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

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
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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

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 Justifications for TPL-008-1, Requirement R1
Proposed VRF

Lower

NERC VRF Discussion

A VRF of Lower is appropriate due to the fact that the Planning Coordinators, in conjunction with its
Transmission Planner(s) will determine joint responsibilities for requirements throughout TPL-008-1.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

5

VSLs for TPL-008-1, Requirement R1
Lower

Moderate

High

Severe

The responsible entity completed
its individual and joint
responsibilities such that the
Extreme Temperature Assessment
was completed, but it was
completed less than or equal to six
months late.

The responsible entity completed
its individual and joint
responsibilities such that the
Extreme Temperature Assessment
was completed, but it was
completed more than six months
but less than or equal to 12 months
late.

The responsible entity completed
its individual and joint
responsibilities such that the
Extreme Temperature Assessment
was completed, but it was
completed more than 12 months
but less than or equal to 18 months
late.

The Planning Coordinator, in
conjunction with its Transmission
Planner(s), failed to identify
individual and joint responsibilities
for completing the Extreme
Temperature Assessment.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

OR
The responsible entity completed
its individual and joint
responsibilities such that the
Extreme Temperature Assessment
was completed, but it was
completed more than 18 months
late.

6

VSL Justifications for TPL-008-1, Requirement R1
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the Planning Coordinator and Transmission Planner to determine
who completes the responsibilities throughout TPL-008-1. The responsibilities documentation will either be
developed or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

7

VRF Justifications for TPL-008-1, Requirement R2
Proposed VRF

High

NERC VRF Discussion

A VRF of high is appropriate due to the fact that selecting a benchmark event to perform an extreme
temperature assessment can affect the grid based on planning analysis for future events.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

8

VSLs for TPL-008-1, Requirement R2
Lower
N/A

Moderate
N/A

High

Severe

The Planning Coordinator
coordinated with all Planning
Coordinators within each identified
zone to select one common
extreme heat and one common
extreme cold benchmark
temperature event for completing
the Extreme Temperature
Assessment, but one of the
selected events failed to meet all
the criteria of Requirement R2.

The Planning Coordinator
coordinated with all Planning
Coordinators within each identified
zone to select one common
extreme heat and one common
extreme cold benchmark
temperature event for completing
the Extreme Temperature
Assessment, but both of the
selected events failed to meet all of
the criteria of Requirement R2.
OR
The Planning Coordinator failed to
coordinate with all Planning
Coordinators within each identified
zone to select to select one
common extreme heat and one
common extreme cold benchmark
temperature event for completing
the Extreme Temperature
Assessment.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

9

VSL Justifications for TPL-008-1, Requirement R2
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

This VSL has been assigned as a binary due to the benchmark event needing to be selected for benchmark
planning cases to be completed. You either select a benchmark event or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

10

VRF Justifications for TPL-008-1, Requirement R3
Proposed VRF

Medium

NERC VRF Discussion

A VRF of medium is appropriate due to the fact that it is important to develop and maintain System models
within an entity’s planning area for performing Extreme Temperature Assessments. Connecting to MOD-032 to
provide important data needed to assist entities with System models is also important for accurate information
to be used.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

11

VSLs for TPL-008-1, Requirement R3
Lower
N/A

Moderate
N/A

High
N/A

Severe
The Planning Coordinator did not
coordinate with all Planning
Coordinators within each of its
identified zone(s) to implement a
process for developing benchmark
planning cases.
OR
The Planning Coordinator
coordinated with all Planning
Coordinators within each of its
identified zone(s) to implement a
process for developing benchmark
planning cases, but the process did
not include all of the required
elements.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

12

VSL Justifications for TPL-008-1, Requirement R3
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either develops and maintains the System
models within its planning area or it does not develop and maintain the System models within its planning area.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

13

VRF Justifications for TPL-008-1, Requirement R4
Proposed VRF

High

NERC VRF Discussion

The VRF of High is appropriate because it could directly affect the electrical state or capability of the BPS if
coordination is not completed for benchmark planning cases and sensitivity cases for the Extreme Temperature
Assessment results.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

14

VSLs for TPL-008-1, Requirement R4
Lower
N/A

Moderate
N/A

High
N/A

Severe
The responsible entity, as identified
in Requirement R1, did not use the
coordination process to develop
benchmark planning cases or
sensitivity cases.
OR
The responsible entity, as identified
in Requirement R1, used the
coordination process to develop
benchmark planning cases and
sensitivity cases, but did not use
data consistent with that provided
in accordance with the MOD-032
standard, supplemented by other
sources as needed, for one or more
of the required cases.
OR
The responsible entity, as identified
in Requirement R1, used the
coordination process and data
consistent with that provided in
accordance with the MOD-032
standard, supplemented as
needed, but failed to develop one
or more of the required planning or
sensitivity cases.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

15

VSL Justifications for TPL-008-1, Requirement R4
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the Planning Coordinator to develop and implement a process for
coordinating the development of benchmark planning cases. The benchmark planning cases will either be
developed and implemented or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

16

VRF Justifications for TPL-008-1, Requirement R5
Proposed VRF

Medium

NERC VRF Discussion

A VRF of medium is appropriate due to the importance of having criteria for acceptable System steady state
voltage limits of post-Contingency voltage deviations for performing Extreme Temperature Assessments.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

17

VSLs for TPL-008-1, Requirement R5
Lower
N/A

Moderate
N/A

High
N/A

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

Severe
The responsible entity, as identified
in Requirement R1, did not have
criteria for acceptable System
steady state voltage limits and
post-Contingency voltage
deviations for completing the
Extreme Temperature Assessment.

18

VSL Justifications for TPL-008-1, Requirement R5
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either having acceptable criteria for System
steady state voltage limits and post-contingency voltage deviations or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

19

VRF Justifications for TPL-008-1, Requirement R6
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate due to the importance of defining and documenting the criteria or methodology for
System instability, uncontrolled separation, or Cascading.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

20

VSLs for TPL-008-1, Requirement R6
Lower
N/A

Moderate
N/A

High
N/A

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

Severe
The responsible entity, as identified
in Requirement R1, failed to define
or document the criteria or
methodology to be used in the
Extreme Temperature Assessment
to identify instability, uncontrolled
separation, or Cascading within an
Interconnection.

21

VSL Justifications for TPL-008-1, Requirement R6
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

22

VRF Justifications for TPL-008-1, Requirement R7
Proposed VRF

Medium

NERC VRF Discussion

A VRF of medium is appropriate for this requirement. Identifying Contingencies for performing Extreme
Temperature Assessments for each of the event categories in Table 1 can indirectly impact the BES.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

23

VSLs for TPL-008-1, Requirement R7
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity, as identified
in Requirement R1, identified
Contingencies for each category in
Table 1 that are expected to
produce more severe System
impacts on its portion of the Bulk
Electric System, but did not include
the rationale for those
Contingencies selected for
evaluation as supporting
information.

The responsible entity, as identified
in Requirement R1, did not identify
Contingencies for each category in
Table 1 that are expected to
produce more severe System
impacts on its portion of the Bulk
Electric System.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

24

VSL Justifications for TPL-008-1, Requirement R7
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

25

VRF Justifications for TPL-008-1, Requirement R8
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate due to the importance of performing an Extreme Temperature Assessment every 5
years.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

26

VSLs for TPL-008-1, Requirement R8
Lower

Moderate

High

Severe

The responsible entity, as identified
in Requirement R1, completed
steady state and transient stability
analyses in the Extreme
Temperature Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for one
or more sensitivity cases in
accordance with Requirement R8.

The responsible entity, as identified
in Requirement R1, completed
steady state and transient stability
analyses in the Extreme
Temperature Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for one
or more benchmark planning cases
in accordance with Requirement
R8.

The responsible entity, as identified
in Requirement R1, completed
steady state and transient stability
analyses in the Extreme
Temperature Assessment using the
Contingencies identified in
Requirement R7, but failed to
evaluate and document results for
one or more of the sensitivity cases
in accordance with Requirement
R8.

The responsible entity, as identified
in Requirement R1, completed
steady state and transient stability
analyses in the Extreme
Temperature Assessment using the
Contingencies identified in
Requirement R7, but failed to
evaluate and document results for
one or more of the benchmark
planning cases in accordance with
Requirement R8.
OR
The responsible entity, as identified
in Requirement R1, failed to
complete steady state or transient
stability analyses and document
results in the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, in accordance
with Requirement R8.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

27

VSL Justifications for TPL-008-1, Requirement R8
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

28

VRF Justifications for TPL-008-1, Requirement R9
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate for this requirement. Developing a Corrective Action Plan is important to the BES as
it assists entities when Systems are unable to meet performance requirements.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

29

VSLs for TPL-008-1, Requirement R9
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity, as identified
in Requirement R1, developed a
Corrective Action Plan in
accordance with Requirement R9,
but failed to make its Corrective
Action Plan available to, or solicit
feedback from, applicable
regulatory authorities or governing
bodies responsible for retail
electric service issues.

The responsible entity, as identified
in Requirement R1, failed to
develop a Corrective Action Plan
when the benchmark planning case
study results indicate the System is
unable to meet performance
requirements for the Table 1 P0 or
P1 Contingencies.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

OR
The responsible entity, as identified
in Requirement R1, developed a
Corrective Action Plan, but it was
missing one or more of the
elements of Requirement R9 Part
9.2-9.4 (as applicable).

30

VSL Justifications for TPL-008-1, Requirement R9
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either having acceptable criteria for System
steady state voltage limits and post-contingency voltage deviations or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

31

VRF Justifications for TPL-008-1, Requirement R10
Proposed VRF

Lower

NERC VRF Discussion

A VRF of lower has been assigned to Requirement R10. Documenting possible actions to reduce the likelihood
or mitigate the consequences and adverse impacts are administrative in nature.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

32

VSLs for TPL-008-1, Requirement R10
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity, as identified
in Requirement R1, evaluated and
documented possible actions to
reduce the likelihood or mitigate
the consequences and adverse
impacts of the event(s) when
analyses conclude there could be
instability, uncontrolled separation,
or Cascading within an
Interconnection where required
under Requirement R10 Part 10.1,
but failed to evaluate and
document possible actions where
required under Requirement R10
Part 10.2.

The responsible entity, as identified
in Requirement R1, evaluated and
documented possible actions to
reduce the likelihood or mitigate
the consequences and adverse
impacts of the event(s) when
analyses conclude there could be
instability, uncontrolled separation,
or Cascading within an
Interconnection where required
under Requirement R10 Part 10.2,
but failed to evaluate and
document possible actions where
required under Requirement R10
Part 10.1.
OR
The responsible entity, as identified
in Requirement R1, failed to
evaluate and document possible
actions to reduce the likelihood or
mitigate the consequences and
adverse impacts of the event(s)
when analyses conclude there
could be instability, uncontrolled
separation, or Cascading within an
Interconnection where required
under Requirement R10 Parts 10.1
and 10.2.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

33

VSL Justifications for TPL-008-1, Requirement R10
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the fact that the responsible entity will have evaluated and
documented possible actions to mitigate adverse impacts.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

34

VRF Justifications for TPL-008-1, Requirement R11
Proposed VRF

Medium

NERC VRF Discussion

The VRF of Medium is appropriate because it could directly affect the electrical state or capability of the BES if
entities are not aware of the results from its Extreme Temperature Assessment results.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

35

VSLs for TPL-008-1, Requirement R11
Lower

Moderate

High

Severe

The responsible entity, as identified
in Requirement R1, provided its
Extreme Temperature Assessment
results to functional entities having
a reliability related need who
requested the information in
writing, but it was more than 60
days but less than or equal to 80
days following the request.

The responsible entity, as identified
in Requirement R1, provided its
Extreme Temperature Assessment
results to functional entities having
a reliability related need who
requested the information in
writing, but it was more than 80
days but less than or equal to 100
days following the request.

The responsible entity, as identified
in Requirement R1, provided its
Extreme Temperature Assessment
results to functional entities having
a reliability related need who
requested the information in
writing, but it was more than 100
days but less than or equal to 120
days following the request.

The responsible entity, as identified
in Requirement R1, provided its
Extreme Temperature Assessment
results to functional entities having
a reliability related need who
requested the information in
writing, but it was more than 120
days following the request.
OR
The responsible entity, as identified
in Requirement R1, did not provide
its Extreme Temperature
Assessment results to functional
entities having a reliability related
need who submitted a written
request for the information.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

36

VSL Justifications for TPL-008-1, Requirement R11
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | October 2024

37

Consideration of FERC Order 896 Directives

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
October 2024
On June 15, 2023, FERC issued a Final Rule, Order No. 896, directing NERC to develop a new or modified Reliability Standard to address a lack
of a long-term planning requirement(s) for extreme heat and cold weather events. Specifically, FERC directed NERC to develop modifications to
Reliability Standard TPL-001-5.1 or to develop a new Reliability Standard to require the following: (1) development of benchmark planning
cases based on major prior extreme heat and cold weather events and/or meteorological projections; (2) planning for extreme heat and cold
weather events using steady state and transient stability analyses expanded to cover a range of extreme weather scenarios including the
expected resource mix's availability during extreme heat and cold weather conditions, and including the wide-area impacts of extreme heat
and cold weather; and (3) development of corrective action plans that mitigate any instances where performance requirements for extreme
heat and cold weather events are not met. FERC directed NERC to submit a new or revised standard within 18 months, or by December 2024.
The below provides the directives from FERC Order 896 along with the drafting team’s consideration of the directives.

Directive Language

FERC Order 896 Directives

P35. “[W]e direct NERC to: (1) develop extreme heat and cold weather
benchmark events, and (2) require the development of benchmark
planning cases based on identified benchmark events.”
P36: “…As recommended by commenters, NERC should consider the
examples of approaches for defining benchmark events identified in the
NOPR (e.g., the use of projected frequency or probability distribution).
NERC may also consider other approaches that achieve the objectives
outlined in this final rule.”

Business Use

Consideration of Directives

The ERO has worked with respective subject matter experts, including
climate experts, the six regions, etc., to explore extreme heat and extreme
cold benchmark temperature events. NERC, in consultation with climate
data subject matter expert consultants on the benchmark events, utilized
publicly available modeled data to address the requirements of TPL-008-1
that define extreme heat and extreme cold benchmark temperature
events.
Specifically, based on the available data, the drafting team determined that
extreme benchmark temperature events must: 1) consider no less than
forty years of historical temperature data, 2) include recent temperature

RELIABILITY | RESILIENCE | SECURITY

Directive Language

FERC Order 896 Directives

Consideration of Directives

data due to ongoing climate changes, and 3) represent one of the twenty
worst extreme temperature conditions over the forty year period, based on
a 3-day rolling average of daily maximum (heat) or minimum (cold)
temperatures.
The ERO will maintain a library of benchmark temperature events that
meet these requirements. Responsible entities will be able to review and
select benchmark temperature events from this library to assist with the
development of benchmark planning cases. However, responsible entities
may also identify benchmark temperature events via their own processes,
provided that the event meets the criteria of Requirement R2 and is agreed
upon by all PCs within the zone.
Should the extreme heat and cold weather benchmark events provided not
suffice for the entities zone, the Planning Coordinator (PC) in coordination
with all PCs within its zone, may develop a common extreme heat and
extreme cold weather benchmark event to use for the TPL-008-1 Standard.
The drafting team developed requirements within TPL-008-1 to require PCs
within zones to select one common extreme heat benchmark temperature
event and one common extreme cold benchmark temperature event
(Requirement R2). After selecting its benchmark events, the responsible
entity is required to implement a process for coordinating the development
of benchmark planning cases and sensitivity cases among the responsible
entities (Requirement R3) and to develop benchmark planning cases and
sensitivity cases (Requirement R4).

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P37. “Because the impact of most extreme heat and cold events spans
beyond the footprints of individual planning entities, it is important that all
responsible entities likely to be impacted by the same extreme weather
events use consistent benchmark events. Doing so is important to ensuring
that neighboring planning regions are assuming similar weather conditions
and are able to coordinate their assumptions accordingly. As a result,
defining the benchmark event in a manner that provides responsible
entities significant discretion to determine the applicable meteorological
conditions would not meet the objectives of this final rule.”
P38. “[I]n developing extreme heat and cold benchmark events, NERC shall
ensure that benchmark events reflect regional differences in climate and
weather patterns.”

Consideration of Directives

NERC, in consultation with climate data subject matter expert consultants
on benchmark events, developed subregions or “zones” of North America
that are likely to experience similar weather conditions. These zones also
consider practical concerns with coordination such as the boundaries of
Interconnections and Balancing Authority Areas.
The drafting team developed Requirement R2 such that PCs within the
same zone are required to select one common extreme heat benchmark
temperature event and one common extreme cold benchmark
temperature event. This process balances the opportunity to provide input
with the need for common events to be modeled over wide areas.
NERC, in consultation with climate data subject matter expert consultants
on benchmark events, has utilized publicly available modeled data in the
last forty-three years (1980-2022), as well as more than eighty years of
projected hourly meteorology data from PNNL to ensure regional
differences in climate and weather patterns are reflected in the zones
depicted in Attachment 1 of TPL-008-1.
A Map has been added to the TPL-008-1 Standard showing the zones split
throughout the US and Canada. These are to be considered wide area, and
regional differences went into consideration when developing the data
based on extreme historical events over the past 40 years.

P39. “We also direct NERC to include in the Reliability Standard the
framework and criteria that responsible entities shall use to develop from
the relevant benchmark event planning cases to represent potential
weather-related contingencies (e.g., concurrent/correlated generation and
transmission outages, derates) and expected future conditions of the
system such as changes in load, transfers, and generation resource mix,
and impacts on generators sensitive to extreme heat or cold, due to the
weather conditions indicated in the benchmark events. Developing such a

The directive is addressed in Requirements R3 and R4 of the proposed TPL008-1 standard.
Requirement R3 obligates the PC to implement a process to coordinate the
development of the benchmark planning cases and sensitivity cases. This
process shall include: 1) the selection of System models within the LongTerm Transmission Planning Horizon to serve as a starting point for the
benchmark planning cases, 2) forecasted seasonal and temperature

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framework would provide a common design basis for responsible entities
to follow when creating benchmark planning cases. This would not only
help establish a clear set of expectations for responsible entities to follow
when developing benchmark planning events, but also facilitate auditing
and enforcement of the Standard.”

P40. “We also direct NERC to ensure the reliability standard contains
appropriate mechanisms for ensuring the benchmark event reflects up-todate meteorological data.”

P50. “[W]e…direct NERC to require that transmission planning studies
under the new or revised Reliability Standard consider the wide-area
impacts of extreme heat and cold weather. We direct NERC to clearly
describe the process that an entity must use to define the wide-area
boundaries. While commenters provide various views in favor of both a
geographical approach and electrical approach to defining wide-area
boundaries, we do not adopt any one approach in this final rule…NERC
should consider the comments in this proceeding when developing a new
or modified reliability standard that considers the broad area impacts of
extreme heat and cold weather.”

Consideration of Directives

dependent adjustments for Load, generation, Transmission, and transfers
within the zone to represent the selected benchmark temperature events,
3) assumed seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers outside of the zone as needed, and
4) the identification of changes to at least one of generation, real and
reactive forecasted load, or transfers to serve as a sensitivity case.
Requirement R4 obligates the responsible entity to develop benchmark
planning cases and sensitivity cases for performing the Extreme
Temperature Assessment which reflects System conditions from the
selected benchmark events. Requirement R4 also references the NERC
MOD-032 Reliability Standard that provides PCs and Transmission Planners
a mechanism for obtaining the data needed to develop the benchmark
planning cases.
Requirement R2 Part 2.1 requires that the temperature data collected to
identify benchmark temperature events includes 40 years of data “ending
no more than 5 years prior to the time the benchmark temperature events
are selected”. This requirement ensures that the window of time
considered for benchmark temperature events reflects up-to-date data.
The up-to five-year gap was included due to potential lags in data sources.
To understand the complexities of defining wide-area boundaries, the
drafting team reviewed the extreme weather events mentioned within
FERC Order No. 896, as well as the comments received during the FERC
Order proceeding. In addition, NERC consulted with climate data subject
matter experts who evaluated publicly available modeled data in the last
forty-three years (1980-2022) and more than eighty years of projected
hourly meteorology data from PNNL.
The drafting team struck a balance between a geographical approach and
an electrical approach by dividing North America into zones that are likely
to experience similar weather conditions but also consider practical

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P58. “[W]e…direct NERC to develop benchmark events for extreme heat
and cold weather events through the Reliability Standards development
process. We agree … that the development of adequate benchmark events
is critical and should be committed to the subject matter experts on the
standards drafting team. ”

Consideration of Directives

concerns with coordination such as the boundaries of Interconnections and
Balancing Authority Areas. These zones are depicted in Attachment 1 of
TPL-008-1, and PCs will be required to coordinate with all PCs in the zone(s)
they belong to.
The drafting team considered various approaches to developing benchmark
temperature events. With assistance from NERC’s subject matter expert
consultants, the drafting team identified the key components of
temperature events that are necessary for the event to constitute an
adequate benchmark temperature event. These components were
included in Requirement R2.
Specifically, based on the available data, the drafting team determined that
extreme benchmark temperature events must: 1) consider no less than
forty years of historical temperature data, 2) include recent temperature
data due to ongoing climate changes, and 3) represent one of the twenty
worst extreme temperature conditions over the forty year period based on
a 3-day rolling average of daily maximum (heat) or minimum (cold)
temperatures.
The ERO will maintain a library of benchmark temperature events that
meet these requirements. Responsible entities will be able to review and
select benchmark temperature events from this library to assist with the
development of benchmark planning cases. However, responsible entities
may also identify benchmark temperature events via their own processes
provided that the event meets the criteria of Requirement R2 and is agreed
upon by all PCs within the zone.
In addition to describing the minimum requirements of a benchmark
temperature event, Requirement R2 obligates PCs within the same zone to
coordinate in selecting one common extreme heat benchmark
temperature event and one common extreme cold benchmark

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P60. “[W]e…direct NERC to designate the type(s) of entities responsible for
developing benchmark planning cases and conducting wide-area studies
under the new or modified Reliability Standard…benchmark planning cases
should be developed by registered entities such as large planning
coordinators, or groups of planning coordinators, with the capability of
planning on a regional scope.”
P61: “We believe the designated responsible entities should have certain
characteristics, including having a wide-area view of the Bulk-Power
System and the ability to conduct long-term planning studies across a wide
geographic area. The responsible entities should also have the planning
tools, expertise, processes, and procedures to develop benchmark planning
cases and analyze extreme weather events in the long-term planning
horizon.”
P62: “To comply with this directive, NERC may designate the tasks of
developing benchmark planning cases and conducting wide-area studies to
an existing functional entity or a group of functional entities (e.g., a group
of planning coordinators). NERC may also establish a new functional entity
registration to undertake these tasks. In the petition accompanying the
proposed Reliability Standard NERC should explain how the applicable
registered entity or entities meet the objectives outlined above.”

Consideration of Directives

temperature event for completing the Extreme Temperature Assessment.
This coordination is required to ensure the benchmark temperature event
is reflected over a wide-area.
The drafting team discussed that the Transmission Planner (TP) and/or
Planning Coordinator (PC) would be the responsible entities to address TPL008-1 Requirements. Requirement R1 obligates both the TP and PC to
identify their individual and joint responsibilities.
Requirement R3 obligates each PC to implement a process for coordinating
the development of benchmark planning cases and sensitivity cases, using
the selected benchmark temperature events identified in Requirement R2.
This process must be implemented in coordination with all PCs within the
same zone.
Requirement R4 obligates each responsible entity, as identified in
Requirement R1, to use the coordination process developed in accordance
with Requirement R3 and data consistent with that provided in accordance
with the MOD-032 standard, supplemented by other sources as needed, to
develop benchmark planning cases and sensitivity cases.
The identification of joint and individual responsibilities in Requirement R1
provides a measure of flexibility for PCs and TPs to agree on a distribution
of responsibilities. Thus, while PCs are responsible for implementing the
case development process in Requirement R3, TPs may be responsible for
providing data and completing the case development according to that
process.
The development of benchmark planning cases and sensitivity cases will
require cooperation amongst many PCs and TPs. By requiring participation
from all entities within a zone, TPL-008-1 ensures that the group of
functional entities have a sufficient wide-area view of the Bulk Power

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P72. “[W]e direct NERC to require functional entities to share with the
entities responsible for developing benchmark planning cases and
conducting wide-area studies the system information necessary to develop
benchmark planning cases and conduct wide-area studies. Further,
responsible entities must share the study results with affected transmission
operators, transmission owners, generator owners, and other functional
entities with a reliability need for the studies.”

Consideration of Directives

System and the planning tools, expertise, processes and procedures
necessary for developing benchmark planning cases and sensitivity cases.
The directive is addressed in proposed TPL-008-1 in Requirements R3, R4
and R11.
Requirement R3 obligates each PC to implement a process for coordinating
the development of benchmark planning cases, using the selected
benchmark temperature events identified in Requirement R2, among all
Planning Coordinators within a zone.
Requirement R4 obligates each responsible entity, as identified in
Requirement R1, to use the coordination process implemented in
accordance with Requirement R3 and data consistent with that provided in
accordance with the MOD-032 standard, supplemented by other sources as
needed, to develop benchmark planning cases and sensitivity cases.

P73. “Because in this final rule we direct NERC to determine the
responsible entities that will be developing benchmark planning cases and
conducting wide-area studies, it is possible that the selected responsible
entities under the new or modified Reliability Standard will not be able to
request and receive needed data pursuant to MOD-032-1, absent
modification to that Standard.”

Requirement R11 obligates each responsible entity, as identified in
Requirement R1, to provide its Extreme Temperature Assessment results
within 60 calendar days of a request to any functional entity that has a
reliability related need and submits a written request for the information.
The drafting team discussed and determined that data needed to address
the Extreme Temperature Assessment would still be appropriate to receive
through MOD-032. MOD-032 ensures an adequate means of data
collection for transmission planning and requires applicable registered
entities to provide steady-state, dynamic, and short circuit modeling data
to their Transmission Planner(s) and Planning Coordinator(s). As outlined in
Requirement R1 and Attachment 1 of MOD-032, MOD-032 allows various
data collection such as in-service status and capability associated with
demand, generation, and transmission associated with various case types,
scenarios, system operating states, or conditions for the long-term
planning horizon. MOD-032 also requires applicable registered entities to

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P76: “[W]e…direct NERC to address the requirement for wide-area
coordination through the standards development process, giving due
consideration to relevant factors identified by commenters in this
proceeding.”
P77. “[W]e direct NERC to require in the new or modified Reliability
Standard that responsible entities share the results of their wide-area
studies with other registered entities such as transmission operators,
transmission owners, and generator owners that have a reliability related
need for the studies.”
P88. “[W]e direct NERC to require under the new or revised Reliability
Standard the study of concurrent/correlated generator and transmission
outages due to extreme heat and cold events in benchmark events as
described in more detail below.”
P92. “These contingencies (i.e., correlated/concurrent, temperature
sensitive outages, and derates) shall be identified based on similar
contingencies that occurred in recent extreme weather events or expected
to occur in future forecasted events.”
P111. “[W]e direct NERC to require in the proposed new or modified
Reliability Standard that responsible entities perform both steady state and

Consideration of Directives

provide “other information requested by the Planning Coordinator or
Transmission Planner necessary for modeling purposes” for each of the
three types of data required. Because the drafting team determined the
responsible entities that will be developing benchmark planning cases are
limited to Planning Coordinators and Transmission Planners, they will be
able to request and receive needed data pursuant to MOD-032. Thus, the
drafting team believes that there is no need to update MOD-032.
The drafting team reviewed all the extreme weather events mentioned
within the FERC Order 896. For this project, the drafting team focused the
scope of Requirement R3 to require each PC to implement a process for
coordinating the development of benchmark planning cases and sensitivity
cases, using the selected benchmark temperature events identified in
Requirement R2, among all PCs within a zone.
This directive is addressed in proposed TPL-008-1 Requirement R11.
Requirement R11 obligates each responsible entity to provide the widearea study results within 60 calendar days of a request to any functional
entity that has a reliability related need and has submitted a written
request for the information.
This directive is addressed in proposed TPL-008-1 through Requirements R3
and R4. Per Requirement R3 Part 3.2, the benchmark planning case
development process must include forecasted seasonal and temperature
dependent adjustments for Load, generation, Transmission, and transfers
within the zone. Per Requirement R4, the data necessary to build the
benchmark planning cases must be provided via MOD-032, supplemented
by other sources as needed. Any concurrent/correlated generator and
transmission outages due to extreme heat and cold events in benchmark
temperature events should be reflected in the model data and thus
represented in the initial conditions of the benchmark planning cases.
This directive is addressed in proposed TPL-008-1 through Requirement R8
and Table 1.

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transient stability (dynamic) analyses in the extreme heat and cold weather
planning studies. In a steady state analysis, the system components are
modeled as either in-service or out-of-service and the result is a single
point-in-time snapshot of the system in a state of operating equilibrium. A
transient stability (dynamic) analysis examines the system from the start to
the end of a disturbance to determine if the system regains a state of
operating equilibrium. Performing both analyses ensures that the system
has been thoroughly assessed for instability, uncontrolled separation, and
cascading failures in both the steady state and the transient stability
realms.” (internal citations omitted).
P112. “[W]e direct NERC to define a set of contingencies that responsible
entities will be required to consider when conducting wide-area studies of
extreme heat and cold weather events under the new or modified
Reliability Standard. We believe that it is necessary to establish a set of
common contingencies for all responsible entities to analyze. Required
contingencies, such as those listed in Table 1 of Reliability Standard TPL001-5.1 (i.e., category P1 through P7), establish common planning events
that set the starting point for transmission system planning assessments.
Requiring the study of predefined contingencies will ensure a level of
uniformity across planning regions—a feature that will be necessary in the
new or revised Reliability Standard considering that extreme heat and cold
weather events often exceed the geographic boundaries of most existing
planning footprints.”
P113: “[T]he contingencies required in the new or revised Reliability
Standards should reflect the complexities of transmission system planning
studies for extreme heat and cold weather events.”
P116. “[W]e direct NERC to require in the new or modified Reliability
Standard that responsible entities model demand load response in their
extreme weather event planning area. As indicated by several
commenters, because demand load response is generally a mitigating

Consideration of Directives

Requirement R8 requires the responsible entity to complete both steady
state and transient stability analyses and document the assumptions and
results.
Table 1 obligates each responsible entity to perform both steady state and
transient stability analyses and compare the study results against steady
state and stability performance requirements.
This directive is addressed in proposed TPL-008-1 through Requirement R7
and Table 1.
Requirement R7 requires the responsible entity to identify Contingencies
for completing the Extreme Temperature Assessment. The rationale, for
those Contingencies selected for evaluation, shall be available as
supporting information.
The Contingencies for each category in Table 1 of TPL-008-1 correspond to
the well-established Contingencies defined in Reliability Standard TPL-0015.1. Utilizing these well-established Contingencies will ensure a level of
uniformity across planning regions.

TPL-008-1 Requirement R4 meets this directive by requiring each
responsible entity to develop benchmark planning cases using data
consistent with that provided in accordance with the MOD-032 standard,
supplemented by other sources as needed.

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action that involves reducing distribution load during periods of stress to
stabilize the Bulk-Power System, its effect during an extreme weather
event should be modeled.”
P 117: “[I]n addressing this directive, we expect NERC to determine
whether responsible entities will need to take additional steps to ensure
that the impacts of demand load response are accurately modeled in
extreme weather studies, such as by analyzing demand load response as a
sensitivity, as is currently the case under Reliability Standard TPL-001-5.1.”
P124. “[W]e direct NERC to require the use of sensitivity cases to
demonstrate the impact of changes to the assumptions used in the
benchmark planning case. Sensitivity analyses help a transmission planner
to determine if the results of the base case are sensitive to changes in the
inputs. The use of sensitivity analyses is particularly necessary when
studying extreme heat and cold events because some of the assumptions
made when developing a base case may change if temperatures change –
for example, during extreme cold events, load may increase as
temperatures decrease, while a decrease in temperature may result in a
decrease in generation. We… direct NERC to define during the Reliability
Standard development process a baseline set of sensitivities for the new or
modified Reliability Standard. While we do not require the inclusion of any
specific sensitivity in this final rule, NERC should consider including
conditions that vary with temperature such as load, generation, and system
transfers.”

Consideration of Directives

Specifically, Attachment 1 of MOD-032 requires information requested by
the Planning Coordinator or Transmission Planner necessary for modeling
purposes.

This directive is addressed in proposed TPL-008-1 in Requirement R3, which
requires all PCs within the same zone to coordinate to implement a process
for developing benchmark planning cases and sensitivity cases. Sensitivity
cases are used to demonstrate the impact of changes to the basic
assumptions used in the benchmark planning cases. Per Requirement R3
Part 3.4, PCs must include provisions in the case development process to
identify changes to generation, real and reactive forecasted Load, and/or
transfers to develop sensitivity cases.
The identification of changes for sensitivity cases within the coordinated
process of Requirement R3 addresses the directive that precludes
responsible entities from determining sensitivities alone. However, nothing
prevents responsible entities from conducting additional sensitivity studies
they find relevant to their planning areas.

P125. “We do not agree ... that responsible entities alone should determine
the sensitivity cases that must be considered in the responsible entity’s
study. … We…believe that responsible entities should be free to study
additional sensitivities relevant to their planning areas…cooperation will be
necessary between responsible entities conducting extreme heat and
extreme cold weather studies and other registered entities within their
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extreme weather study footprints to ensure the selection of appropriate
sensitivities.”
P134. “[W]e directs NERC to require in the new or modified Reliability
Standard the use of planning methods that ensure adequate consideration
of the broad characteristics of extreme heat and cold weather conditions.
We further direct NERC to determine during the standard development
process whether probabilistic elements can be incorporated into the new
or modified Reliability Standard and implemented presently by responsible
entities. If NERC identifies probabilistic elements which responsible entities
can feasibly implement and that would improve upon existing planning
practices, we expect the inclusion of those methods in the proposed
Reliability Standard.”
P138. “[W]e direct NERC to identify during the standard development
process any probabilistic planning methods that would improve upon
existing planning practices, but that NERC deems infeasible to include in
the proposed Reliability Standard at this time. If any such methods are
identified, NERC shall describe in its petition for approval of the proposed
Reliability Standard the barriers preventing the implementation of those
probabilistic elements. We intend to use this information to determine
whether and what next steps may be warranted to facilitate the use of
probabilistic methods in transmission system planning practices.”
P152. “[W]e direct NERC to require in the new or modified Reliability
Standard the development of extreme weather corrective action plans for
specified instances when performance standards are not met. In addition,
as explained below, we direct NERC to develop certain processes to
facilitate interaction and coordination with applicable regulatory
authorities or governing bodies responsible for retail electric service as
appropriate in implementing a corrective action plan.”

Consideration of Directives

The drafting team discussed probabilistic elements and determined while
probabilistic analysis would be a good step forward, it would be better
suited for the future as the methodology, process, and tools mature.
Probabilistic assessment of generation and transmission facilities for the
benchmark planning cases was discussed during the process of drafting the
TPL-008-1 standard. However, based on the actual extreme heat and
extreme cold events that have occurred, outages for generation and
transmission facilities were unique for each of these events. Thus, it was
challenging to draw correlation for the outages that occurred for different
extreme heat and cold events for different regions and different
timeframes. In addition, the data, available from these events, was limited
to perform an adequate probabilistic assessment. Due to these reasons,
the drafting team has decided not to pursue any probabilistic assessment
for the current TPL-008-1 standard. This, however, does not preclude
future development of probabilistic assessment when having additional
data, as well as mature methodology, process and tools that can provide
meaningful probabilistic assessment for generation and transmission
outages under extreme temperature conditions.
The directive is addressed in the proposed TPL-008-1 Requirement R9.
When the benchmark planning case study results indicate the System is
unable to meet performance requirements for P0 and P1 Contingencies,
Corrective Action Plans (CAPs) must be developed. Additionally, in
accordance with Requirement R9 Part 9.1, responsible entities shall make
their CAP available to, and solicit feedback from, applicable regulatory
authorities or governing bodies responsible for retail electric service issues.

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P155: “[T]he Commission is not directing any specific result or content of
the corrective action plan.”
P157. “[W]e direct NERC to require in the new or modified Reliability
Standard the development of corrective action plans that include
mitigation for specified instances where performance requirements for
extreme heat and cold events are not met—i.e., when certain studies
conducted under the Standard show that an extreme heat or cold event
would result in cascading outages, uncontrolled separation, or instability.”
P158: “[W]e give NERC in this final rule the flexibility to specify the
circumstances that require the development of a corrective action plan.”
P165. “[w]e direct NERC to require in the new or modified Reliability
Standard that responsible entities share their corrective action plans with,
and solicit feedback from, applicable regulatory authorities or governing
bodies responsible for retail electric service issues.”
P167. “Further, because an important goal of transmission planning is to
avoid load shed, any responsible entity that includes non-consequential
load loss in its corrective action plan should also identify and share with
applicable regulatory authorities or governing bodies responsible for retail
electric service alternative corrective actions that would, if approved and
implemented, avoid the use of load shedding.”
P188. “[W]e direct NERC to submit a new or modified Reliability Standard
within 18 months of the date of publication of this final rule in the Federal
Register. Further, we direct NERC to propose an implementation timeline
for the new or modified Reliability Standard, with implementation
beginning no later than 12 months after the effective date of a Commission
order approving the proposed Reliability Standard.”

Consideration of Directives

The directive is addressed in the proposed TPL-008-1 Requirement R9.
When the benchmark planning case study results indicate the system is
unable to meet performance requirements for P0 and P1 Contingencies,
Corrective Action Plans must be developed.

The directive is addressed in the proposed TPL-008-1 Requirement R9.
Requirement R9.1 requires the responsible entities to make their CAP
available and solicit feedback from applicable regulatory authorities or
governing bodies responsible for retail electric service issues.
This directive is addressed in proposed TPL-008-1 Requirement R9.
As stipulated in Requirement R9 Part 9.2, when Non-Consequential Load
Loss is utilized as an element of a CAP for a Table 1 P1 Contingency, the
responsible entity must document the alternative(s) considered, and notify
the applicable regulatory authorities or governing bodies responsible for
retail electric service issues.
The directive is addressed with the publication of TPL-008-1 and will be
filed with the regulatory government no later than December 23, 2024,
within 18 months of the date Order No. 896 was published in the Federal
Register.
The implementation plan addresses Requirement R1 becoming effective 12
months from the effective date of the Commission order approving the

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P193. “[W]e direct NERC to establish an implementation timeline for the
proposed Reliability Standard. In complying with this directive, NERC will
have discretion to develop a phased-in implementation timeline for the
different requirements of the proposed Reliability Standard (i.e.,
developing benchmark cases, conducting studies, developing corrective
action plans). However, this phased-in implementation must begin within
12 months of the effective date of a Commission order approving the
proposed Reliability Standard and must include a clear deadline for
implementation of all requirements.”

Consideration of Directives

TPL-008-1. In addition, phased-in approaches have been provided for other
Requirements needing additional time. See the TPL-008-1 Implementation
Plan.
The implementation plan addresses Requirement R1 becoming effective 12
months from the effective date of the Commission order approving the
TPL-008-1. In addition, phased-in approaches have been provided for other
Requirements needing additional time. See the TPL-008-1 Implementation
Plan.

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Limited Disclosure

DRAFT ERO Enterprise Process for TPL-008-1
Benchmark Weather Event Development and
Maintenance
Standards Development and Engineering Process Document
October 2024

Background

This Electric Reliability Organization (ERO) Enterprise Process for TPL-008-1 1 Benchmark Weather Event
Development and Maintenance addresses how ERO Enterprise staff will develop and maintain a library of
benchmark weather events (herein as the Weather Event Library) to be used by Planning Coordinators and
Transmission Planners for TPL-008-1 studies. Per Requirement R3 of TPL-008-1 and consistent with
directives outlined in FERC Order No. 896 2, Planning Coordinators and Transmission Planners will have
benchmark temperature events available via the Weather Event Library to select from when developing
their benchmark planning cases.

Purpose

The purpose of this process document is to formalize a repeatable approach to develop and maintain the
Weather Event Library. While both the TPL-008-1 study requirements and this process are in the initial
stages of development, it is essential that industry is informed of this process and how it will be designed
and implemented following the completion of NERC Project 2023-07. This process document outlines an
initial set of process objectives and approach but is not considered to be complete at this time. This
document will be revised as needed throughout the development of NERC Project 2023-07.

Document Maintenance

NERC will maintain this document to assure it is consistent with acceptable practices and publicly available.
This document will be reviewed as it is implemented. Updates will be made by NERC Standards
Development and Engineering, as needed, to reflect lessons learned as the process matures. Any
substantive changes to this process, supplemental/attached criteria, or other guidance to be used by NERC
in developing additional benchmark events, archiving/removing benchmark events, or other modifications
to the Weather Event Library, will be reviewed in consultation with NERC Legal, NERC Compliance
Assurance, Zoneal Entity staff, and FERC. Approved substantive revisions to this document will be detailed
in the Appendix, broadly communicated to industry, and included as part of informational filings to FERC.

1
2

Link pending final approval of TPL-008-1
FERC Docket No. RM22-10-000; Order No. 896; https://www.ferc.gov/media/e-1-rm22-10-000; June 15, 2023

RELIABILITY | RESILIENCE | SECURITY

Definitions

Refer to the NERC Glossary of Terms 3 for the below capitalized terms used in this process.
•

Affected Zoneal Entity (ARE)

•

Compliance Enforcement Authority (CEA)

•

Coordinated Oversight

•

Extreme Temperature Assessment (ETA)

•

Lead Zoneal Entity (LRE)

•

Multi-Zone Registered Entity (MRRE)

Process Overview

The following is a five-year iterative process coinciding with Planning Coordinator and Transmission Planner
implementation of TPL-008-1. As TPL-008-1 and associated benchmark event(s) will be submitted to FERC
in December 2024, the first iteration of this process will cover five years (2025—2029).
•

•

•

•

•

December 2024


Weather Event Library developed and ready to go live for industry.



Benchmark Events, for the first five-years required per the TPL-008-1 Reliability Standard,
completed and uploaded to the Weather Event Library.

Year One (2025):


ERO to provide Weather Event Library training.



ERO to engage with industry subject matter experts (SMEs), Planning Coordinators, research
labs, and trade organizations, and NERC technical committees on additional and updated criteria
for developing benchmark events.

Year Two (2026):


ERO to initiate review of benchmark event criteria, identify any changes needed, and
incorporate feedback from year one.



ERO to deliver a webinar on updated criteria for developing benchmark events.

Year Three (2027):


ERO to develop new benchmark events 4 based on updated criteria in year two.



ERO to update the Weather Event Library with updated benchmark events.

Year Four (2028):


3
4

ERO to draft informational filing with FERC.

NERC Glossary of Terms: Glossary_of_Terms.pdf (nerc.com)
Note: This is for the second iteration of benchmark events being developed.

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

2

o ERO will engage with industry subject matter experts (SMEs), Planning Coordinators,
research labs, and trade organizations, and NERC technical committees on additional
information needed.
•

Year Five (2029):


ERO to File informational filing with FERC.



ERO to conduct review of this process and make necessary revisions based on lessons-learned
and feedback (e.g., CMEP feedback loops, FERC, SMEs)



ERO to provide training on benchmark event process and changes to the Weather Event Library.

Year 1
Year 2
Year 3
Year4
Year 5

•Deliver Weather Event Library Training
•Develop training and guidance for planning case development

•Review and modify benchmark event criteria
•Informational session on updated criteria

•Update library with new/removed benchmark events

• ERO to draft Informational filing to FERC for any change to criteria and modifications to Weather
Events Library

•Informational filing to FERC for any change to criteria and modifications to Weather Events Library
•Review process and revise based on lessons learned and other feedback loops
•Update Weather Event Library training

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

3

Criteria in Attachment B

Scoping
While the development of the extreme weather event library was intended to be comprehensive, it was
not exhaustive. Instead, this initial assessment is a part of a multi-year effort by NERC and industry to
develop a robust, North American weather dataset and detailed process for extreme weather events. In
the interim, this library of extreme heat and cold events has notable considerations:
• Only extreme heat and cold temperature events were evaluated. The analysis did not assess other
weather events such as hydrologic droughts, wind and solar droughts, wildfires, hurricanes, or other
extreme weather events that could jeopardize grid reliability.
• Only historical meteorological data was considered. The analysis did not incorporate climate
projections or future weather patterns.
• The analysis identified extreme events over a 43-year historical record and did not give higher
priority to recent events
• The study is limited in identifying extreme events, not validating or explaining meteorological drivers
of that event
• The analysis relied on historical reanalysis and modeled weather data rather than historical observed
data for the United States (A smaller observed dataset was used for Canada).
Data Sources
A Pacific Northwest National Laboratory (PNNL) weather dataset 5 used in this study consists of 43 years
(1980-2022) of historical hourly meteorology and roughly 80 years (2020-2099) of projected hourly
meteorology. Hourly observations were dynamically downscaled from historical reanalysis of ERA5 data
into higher temporal and spatial resolutions using the Weather Research and Forecasting Model (WRF). The
model resolution consisted of 12km2 areas that were spatially-averaged by county and then populationweighted to 54 Balancing Authorities (BAs) in the conterminous United States. The variables included in the
final BA weather data are listed in Table 1. While additional parameters like humidity, solar irradiance, and
wind speed are available in the dataset, the identification of extreme weather events in this study was solely
determined by the temperature value.
Table 1: Weather Variables in PNNL Dataset

5 Burleyson, C., Thurber, T., & Vernon, C. (2023). Projections of Hourly Meteorology by Balancing Authority Based on the IM3/HyperFACETS
Thermodynamic Global Warming (TGW) Simulations (v1.0.0) [Data set]. MSD-LIVE Data Repository. https://doi.org/10.57931/1960530

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

4

The PNNL dataset and contributing model were chosen for this study due to the consistency, breadth and
granularity of the weather data. The availability of weather data at the BA-level coincides with topology
standards in power-system coordination in North America. Temperature observation methods can differ
zoneally, so a standardized weather model, such as one in the PNNL dataset, offers unparallelled data
consistency across large geographical areas.
Topology
The zone topology is a function of balancing authority jurisdiction and general knowledge of zoneal weather
patterns. The goal of the topology was to split the North American System into several distinct zones that
have similar electric power system properties (i.e. balancing authority and interconnections) and similar
weather or climatological patterns. Balancing authorities with large areas of jurisdiction, exclusively ISOs
and RTOs, are assigned their own weather zone. In geographical areas comprised of multiple balancing
authorities, generalized weather zones are created to best represent zoneal weather patterns.
Table 2: Balancing Authority to Weather Zone Mappings
Zone
Midwest
New England
Central US
Texas
New York
Central Atlantic
California
Pacific Northwest
Rocky Mountain
Great Basin
Southwest
Southeast
Florida

Balancing Authorities
MISO
ISONE
SPP
ERCOT
NYISO
PJM
5 balancing authorities
10 balancing authorities
3 balancing authorities
4 balancing authorities
6 balancing authorities
7 balancing authorities
9 balancing authorities

In addition to the 13 weather zones representing the United States, three weather zones were developed
to represent Eastern, Central, and Western Canada. The PNNL weather dataset does not contain data for
Canada, so this study compiled observed weather data from weather stations in the lower Canadian
Provinces. The sixteen weather zones best represent the area of study and complement the granularity of
available data. A graphical representation of the final weather zones is shown in Figure 1.
Table 3: Canadian Weather Stations to Weather Zone Mappings

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5

Weather Zones
Eastern Canada
Central Canada
Western Canada

Province
Ontario
Quebec
New Brunswick
Nova Scotia
Saskatchewan
Manitoba
British Columbia
Alberta

Weather Stations
1 weather station
3 weather stations
1 weather station
1 weather station
2 weather stations
1 weather station
2 weather stations
2 weather stations

Figure 1: North American Weather Zones for Extreme Weather Events

Event Selection Process
Extreme weather events are defined in this study as extremely hot or cold multi-day events spanning across
multiple weather zones. The process to select these extreme events used temperature as the sole defining
variable, with emphasis placed on date ranges where multiple weather zones were experiencing historically
hot or cold temperatures.
Aggregating balancing authority data to geographical weather zones
Following the topology detailed above, the hourly temperature observations from either the PNNL weather
dataset or Canadian weather stations are assigned to weather zones. For each balancing area in the United
States, the PNNL data is aggregated from a county-level basis up to the balancing authority based on the

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

6

population in each county. The balancing authority temperature aggregation was therefore provided in the
PNNL dataset.
Additional aggregations were required to develop an average minimum, average, and maximum
temperature for zones with multiple balancing authorities in the Northwest, Southwest, and Southeast. In
these weather zones, the hourly temperature of each balancing authority was weighted by the 2022 peak
load value reported in the EIA Form-861 database. For the Canadian zones, weather station temperature
observations were assigned to the nearest population center and weighted by 2021 Census population.
Calculating Three-Day Rolling Average Min/Max Temperatures
Rather than isolating single hours of extreme weather, the rolling 3-day average of minimum and maximum
daily temperatures are chosen to represent prolonged periods of extreme weather. The three-day
averaging period is centered on every day in the data set (January 1, 1980, to December 31, 2022) and
identifies the average minimum and maximum temperature from the day before, day of, and day after. The
output of this process develops a dataset of multi-day minimum and maximum temperatures to filter out
individual days of extreme heat or cold under the assumption that the power system is more challenged by
sustained periods of extreme heat or cold due to cumulative effects on increasing demand and generator
outages.
Selecting and Ranking Extreme Weather Events by Severity
Once 3-day average temperatures were calculated for every day, the forty coldest minimum values and
forty warmest maximum values were isolated and ranked for each zone, with rank 1 illustrating the most
extreme event. To avoid overlap of events within the same period, any ranked weather events within one
week of another would be removed in favor of the most extreme event. For example, if a zone’s seventhand tenth-most extreme event occur within a 7-day period, only the day with the seventh-most extreme
event would remain in the event database. As a result, some zones may have a discontinuous ranked list
given the removal of “duplicate” events.
A similar one-week overlap method was developed to group contemporaneous extreme weather events
amongst weather zones. First, all event dates were expanded to have a one-week “overlap period” centered
on each date. Then, beginning with the earliest event date, all events that share at least one day of their
overlap periods with the selected event date’s overlap period will be grouped together. The final event date
range will take the earliest and latest dates of all grouped event overlap periods.
The design of the distinct event date ranges encourages multiple weather zones to share extreme weather
events over the course of a one- to two-week event period. To graphically represent the shared extreme
events, all event ranges are listed with the affected zones’ ranks in west-to-east order. A final shortlist of
extreme weather events was developed across all zones. This list included the top one and two most
extreme events, done separately for heat and cold periods. Any event that included at least three zones
experience a top five event simultaneous was also included. For example, if PJM, NYISO, and ISONE all
experienced a top five extreme event, but it was not a top one or two event for any zone in isolation, the
event was included in the final shortlist.

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

7

Results
The result tables show the filtered list of event date ranges with the event ranks for each affected zone; a
lower rank represents a more extreme event and is shaded darker.
Cold Events
The cold events shown in Table 4 demonstrate more concentrated events among nearby zones, with the
most extreme temperature event occurring December 20th to December 29th, 1983. The event uniquely
spanned across the conterminous United States and yielded top ten coldest 3-day average minimum
temperatures in 10 different weather zones.
Under these results, the following cold events are recommended for the NERC library:
• 12/17/1990 – 1/2/1991 for the Western U.S. and Canada
o 12/21 for Pacific NW
o 12/22 for Rocky Mountain, Great Basin, California
o 12/23 for Southwest
o 12/29 for Western Canada
• 12/19/1989 – 12/27/1989 for Central and Southeast U.S. and Canada
o 12/23 for Central Canada
o 12/24 for Central US
o 12/25 for Texas, Midwest, Southeast
o 12/26 for Florida
• 1/13/1994 – 1/29/1994 for the Northeast U.S. and Canada
o 1/16 for New England, Eastern Canada
o 1/20 for Central Atlantic, New York
Table 4: Shortlist of Cold Events

It is important to note that these weather events do not affect all zones simultaneously, but instead move
across the continent in predictable patterns. This has important implications for power system operations
and reliability as load and generator availability may be affected in different zones in different times. An
example of this is from the 1983 event shown geographically in Figure 2. In this example, the worst case
does not occur at the same time in each zone and ideally multiple time periods should be assessed by the
planning coordinators.

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8

Figure 2: Snippets of Animated Weather Event Temperature Map

Heat Events
The heat events shown in Table 5 are more numerous and disparate from one another. In other words,
while extreme cold events tend to affect large geographies simultaneously, heat events can be more
localized. The unconcentrated nature of heat events makes selecting the most extreme event more
ambiguous.
Under these results, the following heat events are recommended for the NERC library:

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

9

•

•

•

7/13/2006 – 7/26/2006 for the Western U.S. and Canada
o 7/16 for Rocky Mountain, Great Basin
o 7/22 for Western Canada, Pacific NW
o 7/23 for California, Southwest
6/21/2012 – 7/9/2012 for Central and Southeast U.S. and Canada
o 6/26 for Texas
o 6/28 for Central Canada, Central US
o 6/30 for Southeast, Florida
o 7/5 for Midwest
7/16/2021 – 7/25/2021 for the Northeast U.S. and Canada
o 7/21 for Central Atlantic, Eastern Canada
o 7/22 for New York, New England
Table 5: Shortlist of Heat Events

Recommendations
The results of this study should inform planning coordinators of potential dates of when to study power
system conditions under extreme weather scenarios. While the final selection of event date ranges aligns
with historical records of extreme weather, a few recommendations and considerations should be made
before proceeding with this study’s results.
• Planning coordinators should assess the entire list of distinct events shown and determine which
events were the most extreme for their jurisdiction along with neighboring areas
• Modelled temperature data provides widespread consistency of weather data across many years
and many zones. Observed temperature data can recognizably vary from modelled values due to
the variety of observation methods at individual weather stations. The temperatures derived from
the PNNL dataset for the extreme weather event selection can be provided, but actual temperature
values used in planning scenarios may need to be derived from observed weather records for local
consistency.

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

10

•
•
•

While temperature is a strong indicator of extreme weather events, it is not the only indicator
available in historical weather data sets. The inclusion of other weather variables such as humidity
and wind speed could further quantify the severity of extreme weather events.
Care should be taken when developing wind, solar, and generator outage assumptions in the
planning cases, using meteorological information to dispatch.
Exceptions need to be accounted for – including HVDC and switchable units.

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

11

Limited Disclosure

Attachment B: Criteria used to develop the
benchmark events
Criteria

Criteria for benchmark events to be drafted.

TPL-008-1 ERO Enterprise Benchmark Weather Event Development and Maintenance
Process Document Version History
Version
1

Date
TBD

Owner
Standards Staff

Change tracking
Initial Version

RELIABILITY | RESILIENCE | SECURITY

TPL-008-1 Benchmark Temperature Events
November 2024

The below provides extreme heat and extreme cold benchmark temperature event data per the zones identified in Attachment 1 of the TPL008-1 Standard. Should entities not agree with the data provided below, you are welcome to coordinate with all Planning Coordinators within
your zone to developing one common extreme heat benchmark temperature event and one common extreme cold benchmark temperature
event per Requirement R2.
Zone

Daily Data

Canada Central
Florida
ISO-NE
Maritimes
MISO North
MISO South
NYISO
Ontario
PJM
SERC
SPP North
SPP South

Daily
Daily
Daily

California/Mexico
Great Basin
Rocky Mtn
Pacific NW

Daily
Daily
Daily
Daily

Daily
Daily
Daily

Daily
Daily
Daily
Daily
Daily
Daily

Benchmark Events
Top 40 Hottest/Coldest 3-Day Average
Eastern Interconnection
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Western Interconnection
Top 40
Top 40
Top 40
Top 40

Hourly Data Selected Events
N/A
Hourly
Hourly
N/A
Hourly
Hourly
Hourly
N/A
Hourly
Hourly
Hourly
Hourly
Hourly
Hourly
Hourly
Hourly

RELIABILITY | RESILIENCE | SECURITY

WECC Southwest
Canada West

Daily
Daily

ERCOT

Daily

Quebec

Daily

TPL-008-1 Benchmark Temperature Events | November 2024

ERCOT Interconnection
Quebec Interconnection

Top 40
Top 40

Hourly
N/A

Top 40

Hourly

Top 40

N/A

Public

Standards Announcement

Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather
Formal Comment Period Open through October 21, 2024
Now Available

A 15-day formal comment period for draft three of TPL-008-1 – Transmission System Planning
Performance Requirements for Extreme Temperature Events is open through 8 p.m. Eastern,
Monday, October 21, 2024.
The Standards Committee approved waivers to the Standards Process Manual at their December
2023 meeting. These waivers were sought by NERC Standards for reduced formal comment and
ballot periods to assist the drafting teams in expediting the standards development process due to
firm timeline expectations set by FERC Order 896.
The standard drafting team’s considerations of the responses received from the previous comment
period are reflected in this draft of the standard.
Reminder Regarding Corporate RBB Memberships

Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more than
the one permitted representative in a particular Segment must withdraw the duplicate membership(s)
prior to joining new ballot pools or voting on anything as part of an existing ballot pool. Contact
[email protected] to assist with the removal of any duplicate registrations.
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. An unofficial Word
version of the comment form is posted on the project page.
•

Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.

•

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

Public

Next Steps

Additional ballots for the standard and implementation plan, as well as a non-binding poll of the
associated Violation Risk Factors and Violation Severity Levels will be conducted October 11-21, 2024.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Jordan Mallory (via email) or at
404-479-7358. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists"
from the "Service" drop-down menu and specify “Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather observer list” in the Description Box.

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 2023-07 Transmission Planning Performance Requirements for Extreme Weather | October 7, 2024

2

Comment Report
Project Name:

2023-07 Transmission Planning Performance Requirements for Extreme Weather | Draft 3

Comment Period Start Date:

10/7/2024

Comment Period End Date:

10/21/2024

Associated Ballots:

2023-07 Transmission Planning Performance Requirements for Extreme Weather Implementation Plan AB 3 OT
2023-07 Transmission Planning Performance Requirements for Extreme Weather TPL-008-1 AB 3 ST

There were 66 sets of responses, including comments from approximately 156 different people from approximately 101 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. Requirement R1 requires Planning Coordinators (PCs) to identify their zone in the map included in Attachment 1. Do you agree with the
zones identified on this map? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural
justification.
2. The Drafting Team (DT) updated Requirement R2 based on comments received. Do you agree with the updated proposed TPL-008-1
Reliability Standard Requirement? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural
justification.
3. The DT updated Requirements R3 – R4 based on comments received. Do you agree with the updated proposed TPL-008-1 Reliability
Standard Requirements? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural justification.
4. The DT updated Requirements R7 – R8 based on comments received. Do you agree with the updated proposed TPL-008-1 Reliability
Standard Requirements? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural justification.
5. The DT updated Requirements R9 – R11 based on comments received. Do you agree with the updated proposed TPL-008-1 Reliability
Standard Requirements? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural justification.
6. The DT believes proposed modifications in TPL-008-1 provide entities with flexibility to meet the reliability objectives in a cost-effective
manner. Do you agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost-effective approaches,
please provide your recommendation and, if appropriate, technical or procedural justification.
7. Provide any additional comments for the drafting team to consider, including the provided technical rationale document, if desired.

Organization
Name
MRO

Name

Anna
Martinson

Segment(s)

1,2,3,4,5,6

Region

MRO

Group Name

MRO Group

Group Member
Name
Shonda McCain

Group
Member
Organization

Group
Member
Segment(s)

Omaha Public 1,3,5,6
Power District
(OPPD)

Group Member
Region
MRO

Michael Brytowski Great River
Energy

1,3,5,6

MRO

Jamison Cawley

Nebraska
Public Power
District

1,3,5

MRO

Jay Sethi

Manitoba
Hydro (MH)

1,3,5,6

MRO

Husam Al-Hadidi Manitoba
1,3,5,6
Hydro
(System
Preformance)

MRO

Kimberly Bentley Western Area 1,6
Power
Adminstration

MRO

Jaimin Patal

Saskatchewan 1
Power
Coporation
(SPC)

MRO

George Brown

Pattern
Operators LP

5

MRO

Larry Heckert

Alliant Energy 4
(ALTE)

MRO

Terry Harbour

MidAmerican
Energy
Company
(MEC)

1,3

MRO

Dane Rogers

Oklahoma
Gas and
Electric
(OG&E)

1,3,5,6

MRO

Seth Shoemaker Muscatine
Power &
Water

1,3,5,6

MRO

Michael Ayotte

ITC Holdings

1

MRO

Andrew Coffelt

Board of
1,3,5,6
Public UtilitiesKansas (BPU)

MRO

Peter Brown

Invenergy

MRO

5,6

Midcontinent
ISO, Inc.

Jennie Wike

Eversource
Energy

Public Utility
District No. 1

Bobbi Welch

2

Jennie Wike

Joshua
London

MRO,RF,SERC ISO/RTO
Council
Standards
Review
Committee
(SRC) Project
2023-07 TPL008-1 Draft
#3

WECC

1

Joyce Gundry 3

Tacoma
Power

Eversource

CHPD

Angela Wheat

Southwestern 1
Power
Administration

MRO

Bobbi Welch

Midcontinent
ISO, Inc.

2

MRO

Joshua Phillips

Southwest
Power Pool

2

MRO

Patrick Tuttle

Oklahoma
Municipal
Power
Authority

4,5

MRO

Helen Lainis

IESO

2

NPCC

Keith Jonassen

ISO-NE

2

NPCC

Bobbi Welch

MISO

2

RF

Gregory Campoli New York
Independent
System
Operator

2

NPCC

Charles Yeung

SPP

2

MRO

Elizabeth Davis

PJM

2

RF

Jennie Wike

Tacoma
1,3,4,5,6
Public Utilities

WECC

John Merrell

Tacoma
1
Public Utilities
(Tacoma, WA)

WECC

John Nierenberg

Tacoma
3
Public Utilities
(Tacoma, WA)

WECC

Hien Ho

Tacoma
4
Public Utilities
(Tacoma, WA)

WECC

Terry Gifford

Tacoma
6
Public Utilities
(Tacoma, WA)

WECC

Ozan Ferrin

Tacoma
5
Public Utilities
(Tacoma, WA)

WECC

Joshua London

Eversource
Energy

1

NPCC

Vicki O'Leary

Eversource
Energy

3

NPCC

Rebecca Zahler

Public Utility
District No. 1

5

WECC

of Chelan
County

FirstEnergy FirstEnergy
Corporation

National Grid
USA

Northeast
Power
Coordinating
Council

of Chelan
County

Mark Garza

4

Michael Jones 1

Ruida Shu

1,2,3,4,5,6,7,8,9,10 NPCC

FE Voter

Joyce Gundry

Public Utility
District No. 1
of Chelan
County

3

WECC

Diane Landry

Public Utility
District No. 1
of Chelan
County

1

WECC

Tamarra Hardie

Public Utility
District No. 1
of Chelan
County

6

WECC

Julie Severino

FirstEnergy FirstEnergy
Corporation

1

RF

Aaron
Ghodooshim

FirstEnergy FirstEnergy
Corporation

3

RF

Robert Loy

FirstEnergy FirstEnergy
Solutions

5

RF

Mark Garza

FirstEnergyFirstEnergy

1,3,4,5,6

RF

Stacey Sheehan

FirstEnergy FirstEnergy
Corporation

6

RF

National Grid
USA

1

NPCC

Brian Shanahan

National Grid
USA

3

NPCC

Gerry Dunbar

Northeast
Power
Coordinating
Council

10

NPCC

Deidre Altobell

Con Edison

1

NPCC

Michele Tondalo

United
Illuminating
Co.

1

NPCC

Stephanie UllahMazzuca

Orange and
Rockland

1

NPCC

Michael Ridolfino Central
1
Hudson Gas &
Electric Corp.

NPCC

National Grid Michael Jones

NPCC RSC

Randy Buswell

Vermont
1
Electric Power
Company

NPCC

James Grant

NYISO

2

NPCC

Dermot Smyth

Con Ed 1
Consolidated
Edison Co. of
New York

NPCC

David Burke

Orange and
Rockland

3

NPCC

Peter Yost

Con Ed 3
Consolidated
Edison Co. of
New York

NPCC

Salvatore
Spagnolo

New York
Power
Authority

1

NPCC

Sean Bodkin

Dominion Dominion
Resources,
Inc.

6

NPCC

David Kwan

Ontario Power 4
Generation

NPCC

Silvia Mitchell

NextEra
1
Energy Florida Power
and Light Co.

NPCC

Sean Cavote

PSEG

4

NPCC

Jason Chandler

Con Edison

5

NPCC

Tracy MacNicoll

Utility Services 5

NPCC

Shivaz Chopra

New York
Power
Authority

6

NPCC

Vijay Puran

New York
6
State
Department of
Public Service

NPCC

David Kiguel

Independent

7

NPCC

Joel Charlebois

AESI

7

NPCC

Joshua London

Eversource
Energy

1

NPCC

Jeffrey Streifling

NB Power
Corporation

1,4,10

NPCC

Dominion Dominion
Resources,
Inc.

Shannon
Mickens

Sean Bodkin

Shannon
Mickens

6

Dominion

MRO,SPP
RE,WECC

SPP RTO

Joel Charlebois

AESI

7

NPCC

John Hastings

National Grid

1

NPCC

Erin Wilson

NB Power

1

NPCC

James Grant

NYISO

2

NPCC

Michael
Couchesne

ISO-NE

2

NPCC

Kurtis Chong

IESO

2

NPCC

Michele Pagano

Con Edison

4

NPCC

Bendong Sun

Bruce Power

4

NPCC

Carvers Powers

Utility Services 5

NPCC

Wes Yeomans

NYSRC

7

NPCC

Chantal Mazza

Hydro Quebec 1

NPCC

Nicolas Turcotte

Hydro Quebec 2

NPCC

Victoria Crider

Dominion
Energy

3

NA - Not
Applicable

Sean Bodkin

Dominion
Energy

6

NA - Not
Applicable

Steven Belle

Dominion
Energy

1

NA - Not
Applicable

Barbara Marion

Dominion
Energy

5

NA - Not
Applicable

Shannon Mickens Southwest
Power Pool
Inc.

2

MRO

Mia Wilson

Southwest
Power Pool
Inc.

2

MRO

Eddie Watson

Southwest
Power Pool
Inc.

2

MRO

Erin Cullum

Southwest
Power Pool
Inc.

2

MRO

Jonathan Hayes

Southwest
Power Pool
Inc.

2

MRO

Jeff McDiarmid

Southwest
Power Pool
Inc.

2

MRO

Western
Electricity
Coordinating
Council

Steven
Rueckert

10

WECC

Scott Jordan

Southwest
Power Pool
Inc

2

MRO

Mason Favazza

Southwest
Power Pool
Inc

2

MRO

Sherri Maxey

Southwest
Power Pool
Inc.

2

MRO

Josh Phillips

Southwest
Power Pool
Inc.

2

MRO

Steve Rueckert

WECC

10

WECC

Curtis Crews

WECC

10

WECC

1. Requirement R1 requires Planning Coordinators (PCs) to identify their zone in the map included in Attachment 1. Do you agree with the
zones identified on this map? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural
justification.
Devin Shines – LG&E/KU
Answer

Yes

Document Name
Comment
LG&E/KU agrees with the modifications to R1 that clarify the responsibilities to be identified between the PC and TP, and that require the Extreme
Temperature Assessment (ETA) to be completed once every five years. Identification of zones is required in Requirement R2 rather than R1.
LG&E/KU agrees with the content of Attachment 1 and the identification of zones according to the table (not map). LG&E/KU notes that the question in
this comment form was not updated to reflect changes made to the standard just before the comment period (namely, zones being identified in
Requirement R2 and the table of Attachment 1 controlling rather than the table).
Likes

0

Dislikes

0

Response

Michele Tondalo - United Illuminating Co. - 1
Answer

No

Document Name
Comment
Comparing the table and map is confusing. There are 20 regions shown in the map and 17 in the table; it is not clear why there is a discrepancy. In
addition, the map shows the Quebec colored region as part of Eastern Canada which is different than the table, which separates Quebec and Ontario.
Likes

0

Dislikes

0

Response
Donald Lock - Talen Generation, LLC - 5
Answer
Document Name
Comment

No

Many of the zones are very big, often including a large north-to-south range, such that a single heat or cold benchmark event cannot adequately cover
all locations within a zone. Consider MISO in particular – can a single criterion suffice for Minnesota and Louisiana?
Likes

0

Dislikes

0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

No

Document Name
Comment
FirstEnergy supports EEI's response, which state:
In general, EEI member companies see some value in retaining the maps included in the TPL-008-1, however, we remain concerned that the
temperature regions as proposed in those maps (and elsewhere) are in a number of cases far too large to provide meaningful analysis (e.g., MISO and
SPP in particular). Additionally, EEI does not agree that maintaining disconnected parts of SERC and PJM into the broader SERC and PJM
temperature zones makes any sense. For this reason, we do not support the temperature zones as currently proposed and ask that they be
modified. To address our concerns, we suggest at a minimum that 1) SPP and MISO both be split into a north and south region, and 2) the
disconnected portions of SERC and PJM be included into zones that more closely align with their temperature regions.

Likes

0

Dislikes

0

Response
Mark Flanary - Midwest Reliability Organization - 10
Answer

No

Document Name
Comment
The Requirement R1 language doesn't refer to zones. Please see our comments below to question 2.
Likes

0

Dislikes
Response

0

Helen Lainis - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment
The IESO does not support nor agree with the zone mapping for Ontario. The zone developed for Eastern Canada includes the balancing
authority jurisdictions for Ontario, Nova Scotia and New Brunswick. Ontario does not have similar weather and climatological patterns to
Nova Scotia and New Brunswick. Aggregating these 3 balancing authorities to the same geographical weather zone is not supported by the
actual extreme events experienced by each jurisdiction. In fact, Ontario is more likely to share similar weather and climatological patterns
with US neighboring balancing authorities NYISO and ISONE than it does with Nova Scotia and New Brunswick.

We strongly suggest that the Province of Ontario be assigned its own weather zone. In addition, at least 2 more weather stations would need
to be sampled, similar to what is done for Quebec (refer to table in ERO Benchmark Process). It is not clear which weather station is being
currently used for Ontario, but assuming it is from southwestern Ontario (Pearson), weather data from northern (Thunder Bay) and eastern
Ontario (Ottawa) would be required for a more accurate representation of Ontario weather patterns.

Likes

1

Dislikes

Ontario Power Generation Inc., 5, Chitescu Constantin
0

Response
Erin Wilson - NB Power Corporation - New Brunswick Power Transmission Corporation - 5
Answer

No

Document Name
Comment
The zones shown in Attachment 1 lumps Ontario with the Maritimes (New Brunswick, Nova Scotia, and parts of Northern Maine); however, practical
experience has shown that there is no reliability benefit to coordinating the extreme weather planning assessments for two reasons:
•
•

Experience has shown that Ontario and the Maritimes are sufficiently distant from each other as to experience extreme temperature conditions
at different times. An extreme temperature event in Ontario would not occur at the same time as an extreme temperature event in the
Maritimes.
The balancing areas of Ontario and the Maritimes are not adjacent and the capacity of the transmission system to transfer power between
Ontario and the Maritimes is small enough that the power transfered between Ontario and the Maritimes would most likely be negligible during
an extreme temperature event.

For the NPCC region, it would make the most sense to divide the weather zones for extreme weather planning assessments along the boundaries of
the existing Reliability Coordinator areas, resulting in five different weather zones:
•

ISO New York

•
•
•
•

ISO New England
Ontario
Quebec
The Maritimes, including New Brunswick, Nova Scotia, and Northern Maine

In addition to the foregoing, New Brunswick Power would like to support the comments of Helen Lainis, Independent Electricity System Operator.
Note that these comments actually apply to R2, which is the requirements for PCs to identify their zone on the map in Attachment 1 -- R1 is actually
unrelated to the above question.
Likes

0

Dislikes

0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer

No

Document Name
Comment
The zones shown in Attachment 1 lumps Ontario with the Maritimes (New Brunswick, Nova Scotia, and parts of Northern Maine); however, practical
experience has shown that there is no reliability benefit to coordinating the extreme weather planning assessments for two reasons:
•
•

Experience has shown that Ontario and the Maritimes are sufficiently distant from each other as to experience extreme temperature conditions
at different times. An extreme temperature event in Ontario would not occur at the same time as an extreme temperature event in the
Maritimes.
The balancing areas of Ontario and the Maritimes are not adjacent and the capacity of the transmission system to transfer power between
Ontario and the Maritimes is small enough that the power transfered between Ontario and the Maritimes would most likely be negligible during
an extreme temperature event.

For the NPCC region, it would make the most sense to divide the weather zones for extreme weather planning assessments along the boundaries of
the existing Reliability Coordinator areas, resulting in five different weather zones:
•
•
•
•
•

ISO New York
ISO New England
Ontario
Quebec
The Maritimes, including New Brunswick, Nova Scotia, and Northern Maine

In addition to the foregoing, New Brunswick Power would like to support the comments of Helen Lainis, Independent Electricity System Operator.
Note that these comments actually apply to R2, which is the requirements for PCs to identify their zone on the map in Attachment 1 -- R1 is actually
unrelated to the above question.
Likes
Dislikes

0
0

Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
Dominion Energy supports EEI comments
Likes

0

Dislikes

0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

No

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) on question 1
Likes

0

Dislikes

0

Response
Daniel Gacek - Exelon - 1
Answer

No

Document Name
Comment
Exelon does not agree with the zones identified on the map in Attachment 1. We suggest the map should better align to the various temperature
gradients a zone may experience. The map that has been proposed seems to prioritize PC and TP boundaries over identifying the geographic regions
extreme temperature events have occurred in.
Additionally, Exelon supports the comments submitted by the EEI.
Likes

0

Dislikes

0

Response
Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer

No

Document Name
Comment
PNM Resources (PNMR) is concerned with picking weather data that is comparable between New Mexico and Arizona. We believe differences in
weather patterns would impact New Mexico study if building that study to Arizona's summer temperatures.
Likes

0

Dislikes

0

Response
Sharon Darwin - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
Southern Company supports EEI's comments.
Likes

0

Dislikes

0

Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment
In general, EEI member companies see some value in retaining the maps included in the TPL-008-1, however, we remain concerned that the
temperature regions as proposed in those maps (and elsewhere) are in a number of cases far too large to provide meaningful analysis (e.g., MISO and
SPP in particular). Additionally, EEI does not agree that maintaining disconnected parts of SERC and PJM into the broader SERC and PJM
temperature zones makes any sense. For this reason, we do not support the temperature zones as currently proposed and ask that they be
modified. To address our concerns, we suggest at a minimum that 1) SPP and MISO both be split into a north and south region, and 2) the
disconnected portions of SERC and PJM be included into zones that more closely align with their temperature regions.

EEI is also concerned that benchmark temperature events reside outside of this Reliability Standard placing unnecessary compliance risks for
companies. To address this concern, we ask that the benchmark temperature event be included into TPL-008-1 as an attachment.
Likes

0

Dislikes

0

Response
Michael Brytowski - Great River Energy - 3
Answer

No

Document Name
Comment
The MISO zone should be divided into 2 zones – MISO North and MISO south.
The weather differences between Northern Minnesota and Southern Louisiana are too extreme to conduct a meaningful assessment.
The winter temperatures in the MISO benchmark event data are just an average January for Minnesota and those winter temperatures will not be
experienced in Louisiana. Similarly, the SPP zone should be spilt north and south as well.
Likes

1

Dislikes

Scott Brame, N/A, Brame Scott
0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Junji Yamaguchi, Hydro-Quebec (HQ), 1, 5; Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal
Mazza
Answer

No

Document Name
Comment
We support Independent Electricity System Operator’s and NB Power Corporation comments.
Furthermore, Attachment 1 – Extreme Temperature Assessment Zones in accordance with Requirement R2: We agree with Québec being its own
Interconnection in the map and in the table, however Québec is the only area that has its own zone in the table which does not correspond to a Weather
Zone identified in the Benchmark Process. Similarly, it is not in the list of benchmark temperature event data on the project page under “Benchmark
Event Data”. For example, ERCOT is identified as its own Interconnection and has its own list of benchmark temperature events. Another example is
Florida in the SERC region warrants a separate treatment and has its own benchmark temperature event data.
Lastly, the Quebec zone does not appear in the TPL-008 Attachment 1 map, while it is in the table just above. We suggest adding the label “Québec” or
“Quebec Interconnection” in white font in the dark blue space represented by the province of Quebec and changing the color of the province of Québec
to better reflect that it is its own interconnection.
Likes

0

Dislikes

0

Response
Joseph Knight - Joseph Knight On Behalf of: Jacalynn Bentz, Great River Energy, 3, 1, 5, 6; - Joseph Knight
Answer

No

Document Name
Comment
The MISO zone should be divided into 2 zones – MISO North and MISO south.
The weather differences between Northern Minnesota and Southern Louisiana are too extreme to conduct a meaningful assessment.
The winter temperatures in the MISO benchmark event data are just an average January for Minnesota and those winter temperatures will not be
experienced in Louisiana. Similarly, the SPP zone should be spilt north and south as well.
Likes

0

Dislikes

0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

No

Document Name
Comment
AZPS supports the following comments that were submitted by EEI on behalf of its members:
In general, EEI member companies see some value in retaining the maps included in the TPL-008-1, however, we remain concerned that the
temperature regions as proposed in those maps (and elsewhere) are in a number of cases far too large to provide meaningful analysis (e.g., MISO and
SPP in particular). Additionally, EEI does not agree that maintaining disconnected parts of SERC and PJM into the broader SERC and PJM
temperature zones makes any sense. For this reason, we do not support the temperature zones as currently proposed and ask that they be
modified. To address our concerns, we suggest at a minimum that 1) SPP and MISO both be split into a north and south region, and 2) the
disconnected portions of SERC and PJM be included into zones that more closely align with their temperature regions.
EEI is also concerned that benchmark temperature events reside outside of this Reliability Standard placing unnecessary compliance risks for
companies. To address this concern, we ask that the benchmark temperature event be included into TPL-008-1 as an attachment.
Likes

0

Dislikes
Response

0

Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy Houston Electric, LLC (CEHE) supports EEI’s partial response to question 1, in regard to benchmark temperature events residing
outside the Reliability Standard placing unnecessary compliance risks for companies. CEHE requests that the benchmark temperature events be
included into TPL-008-1 as an attachment.
Likes

0

Dislikes

0

Response
Kinte Whitehead - Exelon - 3
Answer

No

Document Name
Comment
Exelon does not agree with the zones identified on the map in Attachment 1. We suggest the map should better align to the various temperature
gradients a zone may experience. The map that has been proposed seems to prioritize PC and TP boundaries over identifying the geographic regions
extreme temperature events have occurred in.
Additionally, Exelon supports the comments submitted by the EEI.
Likes

0

Dislikes

0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer

No

Document Name
Comment
Comparing the table and map is confusing. There are 20 regions shown in the map and 17 in the table; it is not clear why there is a discrepancy. In
addition, the map shows the Quebec colored region as part of Eastern Canada which is different than the table, which separates Quebec and Ontario.
Likes
Dislikes

0
0

Response
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer

No

Document Name
Comment
See EEI Comments
Likes

0

Dislikes

0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

No

Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments.
Likes

0

Dislikes

0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

No

Document Name
Comment
See EEI Comments
Likes

0

Dislikes
Response

0

Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
R2 (not R1) requires PC to identify their zone in the map included in attachment1. The MISO and SPP zones are spread across multiple temperature
regions. This would make it difficult for MISO and SPP to choose a single extreme temperature event that would provide meaningful assessment
results across their respective zones. The MISO and SPP zones should be split into MISO North, MISO South, SPP North, and SPP South. Also, the
disjointed sections of SERC Central are in a different temperature region that others included in the SERC zone. The disjointed section s of SERC
Central should be included in the appropriate MISO or SPP zone that aligns with their temperature region.
Likes

0

Dislikes

0

Response
Wayne Guttormson - SaskPower - 1
Answer

No

Document Name
Comment
Zones are nominally adequate, except Eastern Canada which needs to be split into Ontario and the Maritimes.
Support SPP's comment - "if the goal is for the PCs to study a 1 in 40-year event for temperature that each PC perform a study for their footprint and
share results to the adjacent PCs, similar to the way existing NERC standards are coordinated."

Likes

0

Dislikes

0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

No

Document Name
Comment
ITC sees some value in retaining the maps included in the TPL-008-1, however, we remain very concerned that the temperature regions as proposed in
the map (and elsewhere) are in a number of cases far too large to provide meaningful analysis (e.g., MISO and SPP in particular). Additionally, the
benchmark temperature events identified for both MISO and SPP do not represent what would be considered extreme temperature events due to their

large geographically diverse regions. To address our concerns, we suggest at a minimum that SPP and MISO both be split into a north and south
region.
ITC is also concerned that benchmark temperature events reside outside of this Reliability Standard placing unnecessary compliance risks for
companies. To address this concern, we ask that the benchmark temperature event be included into TPL-008-1 as an attachment.
Likes

0

Dislikes

0

Response
Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

No

Document Name
Comment
Comparing the table and map is confusing. There are 20 regions shown in the map and 17 in the table; it is not clear why there is a discrepancy. In
addition, the map shows the Quebec colored region as part of Eastern Canada which is different than the table, which separates Quebec and Ontario.
Likes

0

Dislikes

0

Response
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer

No

Document Name
Comment
SPP does not have any issues with the eastern interconnect portion of the Table and Map. However, SPP does have concerns with the western portion
of the Table and Map. The Table and Map seem to group together PCs in a way that could create issues when trying to identify which PCs belong to
those zones. There is currently no requirement to post publicly which zone a PC is within, therefore knowing which PC belongs to each zone is not
possible.
Consideration is also needed for when a PC footprint changes in the future for this standard since the Table and Map represent current boundaries. If
these boundaries change in the future this would require either more coordination or a change to the standard to allow for the boundary to change. A
change to the standard would be overly administratively burdensome for such a future change.
There is also a reference in the requirement to Attachment 1 which refers to the Table, however the Map creates confusion when applying the Table
due to the use of color code in the east and the lack of color coding in the west for the northwest region. There seems to be a lack of PC boundaries in
the western footprint denoted in the Map. SPP would offer that if the Map is needed for Table 1 then the PC boundaries in the west should be identified
and color coded appropriately.

Additionally, the technical rationale states the zones have been determined by the Reliability Coordinator (RC) area. SPP believes that breaking the
zone by RC footprint is not accurate and should be divided by the PC footprint especially considering that the standard only applies to the PC. PC and
RC footprints can be drastically different across the grid.
SPP would like to offer a secondary suggestion that if the goal is for the PCs to study a 1 in 40-year event for temperature that each PC perform a study
for their footprint and share results to the adjacent PCs, similar to the way existing NERC standards are coordinated. For instance, there are other
standards that utilize language for the applicable entity to study its PC footprint and coordinate with 1st tier entities. SPP believes that language similar
to this can accomplish the intended goal without creating a burden if the boundaries change in the Map.
Likes

0

Dislikes

0

Response
Greg Sorenson - Greg Sorenson On Behalf of: Tremayne Brown, ReliabilityFirst , 10; - ReliabilityFirst - 10 - RF
Answer

No

Document Name
Comment
When considering this requirement with the others for PC’s that cover large diverse areas like SPP or MISO, the single temperature consideration for
extreme hot or extreme cold does not seem to make sense. For instance, for MISO to use one extreme cold temperature for Texas and for northern
Minnesota when they should consider very different extreme temperatures, an extreme cold temperature of 0 in Texas is normal cold for Minnesota.
Opposite is true for extreme hot temperatures. PC’s should have the ability to select different extreme temperatures within their zone, as worded it does
not appear they have that option. This will work if latitude is considered and PC’s can use different extreme temperatures within their zone
Likes

0

Dislikes

0

Response
Robert Blackney - Edison International - Southern California Edison Company - 1
Answer

No

Document Name
Comment
See comments submitted by Edison Electric Institute.
Likes

0

Dislikes
Response

0

Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

Yes

Document Name
Comment
It is not Requirement R1, which requires PCs to identify their zones. Requirement R2 requires PCs to identify their zones and coordinate with other PCs
in that zone. Manitoba Hydro has no issues with the identification of the Central Canada zone in Attachment 1.
Likes

0

Dislikes

0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

Yes

Document Name
Comment
SNPD has identified a potential typo in Question 1. Requirement R1 does not stipulate that PCs must identify their zone on the map included in
Attachment 1. However, Requirement R2 clearly requires PCs to identify their zone on this map, and SNPD concurs with this requirement.
Likes

0

Dislikes

0

Response
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

Yes

Document Name
Comment
Although this appears to be an R2.
Likes

0

Dislikes

0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF

Answer

Yes

Document Name
Comment
None.
Likes

0

Dislikes

0

Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
We assume this is in reference to Requirement R2.
Likes

0

Dislikes

0

Response
Robert Jones - Seattle City Light - 1,3,4,5,6
Answer

Yes

Document Name
Comment
Assuming this is referencing R2, not R1: The Zones are appropriate, assuming that the sub-zones in the "Northwest Regions" are treated as separate
zones.
Likes

0

Dislikes

0

Response
Bobbi Welch - Midcontinent ISO, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee (SRC) Project 2023-07 TPL-008-1 Draft #3
Answer
Document Name

Yes

Comment
The response to Question 1 is on behalf of MISO since (as the submitter of joint SRC comments) is otherwise unable to submit a Comment Form of its
own.
Likes

0

Dislikes

0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

Yes

Document Name
Comment
PGAE agrees with the zoning, however, overlapping of zones within neighboring entities should be allowed to meet the requirements of extreme
weather conditions. Although we agree that the focus of the study is within the boundary, PCs should have the flexibility to consider maybe a little bit
past the confines of identified zone as identified in Attachment 1.
Likes

0

Dislikes

0

Response
Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Robert Follini - Avista - Avista Corporation - 3
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Kevin Conway - Western Power Pool - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Ben Hammer - Western Area Power Administration - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Srikanth Chennupati - Entergy - 1,3,5,7 - SERC
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Ronald Hoover - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Jennie Wike - Jennie Wike On Behalf of: Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; John Merrell, Tacoma Public Utilities
(Tacoma, WA), 1, 4, 5, 6, 3; John Nierenberg, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; Ozan Ferrin, Tacoma Public Utilities (Tacoma,
WA), 1, 4, 5, 6, 3; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; - Jennie Wike, Group Name Tacoma Power
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Joshua London - Eversource Energy - 1, Group Name Eversource
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer
Document Name
Comment

Yes

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Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer

Yes

Document Name
Comment
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Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

Yes

Document Name
Comment
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0

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Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment
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Response

0

Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
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0

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Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment

Texas RE notes that it is Requirement R2, not Requirement R1 that requires to the PC to identify the zones.

In the Attachment 1 Table, Texas RE recommends revising the Planning Coordinators description to Areas in Texas that are part of the ERCOT
Interconnection. This removes the word jurisdiction, since ERCOT does not have jurisdiction over NERC Reliability Standards.

In Requirement R1, Texas RE recommends the following revision for clarity:
R1. Each Planning Coordinator shall identify, in conjunction with its Transmission Planner(s), shall identify and document each entity’s individual and
joint responsibilities for completing the Extreme Temperature Assessment, which shall include each of the responsibilities described in Requirements
R2 through R11. Each responsible entity shall complete its responsibilities such that the Extreme Temperature Assessment is completed at least once
every five calendar years.

This clarifies that each Planning Coordinator and Transmission Planner(s) shall document the individual and joint responsibilities for completing the
Extreme Temperature Assessment for clarity and to show proof of obligations as the responsible personnel may change from time to time. M1 details
that the Planning Coordinator, in conjunction with its Transmission Planner(s), shall provide documentation of each entity’s individual and joint
responsibilities. However, need for documentation is not included in the Requirement.
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0

2. The Drafting Team (DT) updated Requirement R2 based on comments received. Do you agree with the updated proposed TPL-008-1
Reliability Standard Requirement? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural
justification.
Devin Shines – LG&E/KU
Answer

Yes

Document Name
Comment
LG&E/KU appreciates the effort of the DT to create a process for identifying extreme benchmark temperature events that balances the need for
transparency, practicality, and effectiveness. The process described in Requirement R2 provides entities with sufficient clarity on what constitutes an
extreme benchmark temperature event, while also affording entities flexibility in how and which events are selected.
LG&E/KU would request the DT consider whether Requirement R2 and its VSLs could be modified to address the situation where one (or more)
Planning Coordinators in a zone does not coordinate. As-is, the Requirement R2 language could be understood as all other PCs in that zone also
being out of compliance.
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Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

No

Document Name
Comment
The role of ERO seems to be reduced to footnote 1, the DT further needs to clarify what “maintain” means in this context. PGAE would like to better
understand the benefits of using benchmark libraries over local extreme weather conditions. We would like to see the periodicity of this maintain
obligation for the ERO. If the DT could expand on the footnote 1 to provide clarification of ERO maintaining the library and how often ERO would be
updating the library of benchmark temperature events.
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Michael Goggin - Grid Strategies LLC - 5

Answer

No

Document Name
Comment
the new requirement proposed in R2 2.1 in the updated draft that the event selected represent “one of the 20 most extreme temperature conditions”
may result in entities selecting events that are not representative of the most severe generation shortfalls they are likely to experience. First, entities
should be required to select from a smaller number of most severe events, like the three most severe events. Second, the ranking of events should not
be based on most extreme temperature, but rather most severe generation shortage, accounting for both higher demand and higher generator outage
rates during the event. This will accurately reflect that temperature alone does not determine the severity of an event, as wind speed, insolation, and
other factors affect how extreme cold and heat affect both generator outages and the need for building heating or cooling.
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Response
Carver Powers - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
USV has concerns about the proposed language in R2, Part 2.1. 40 years of temperature data is an immense amount of data. The data collected 40
years ago compared to today’s temperatures may not be accurate and could construed the data from the last 20-25 years. We believe that there have
been enough recent extreme weather events in the last 25 years to accurately consider extreme heat and extreme cold benchmark temperatures. We
recommend that the drafting team consider utilizing a timeline closer to 20 years and not 40 years.
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Response
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer

No

Document Name
Comment
The Table and Map seem to group together PCs in a way that could create issues when trying to identify which PCs belong to those zones. There is
currently no requirement to post which zone the PC is in, therefore knowing which PC belongs to each zone is not possible, specifically for the western
portion of the Table and Map.
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Response
Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

No

Document Name
Comment
The intent of the standard is to perform an extreme temperature assessment, but R2 allows for selection from the “20 most extreme” events from a
period of 40 years. This could result in an entity being able to select an event that is relatively mild but still maintain compliance. This could be mitigated
by narrowing the number of extreme events to select from down to a lower number, for example 10.
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Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
See comments for question1. Additionally, the SDT should consider an official library or other repository from which the common extreme heat
benchmark temperature event and common extreme cold benchmark temperature event is chosen. This library should either be included as an
attachment to this standard, or the official location and maintenance should be documented within this standard.
If no official library is document, this could lead to ambiguities and inconsistencies in performing the assessment and in auditing this requirement.
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0

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Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

No

Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments.

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Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer

No

Document Name
Comment
The intent of the standard is to perform an extreme temperature assessment, but R2 allows for selection from the “20 most extreme” events from a
period of 40 years. This could result in an entity being able to select an event that is relatively mild but still maintain compliance. This could be mitigated
by narrowing the number of extreme events to select from down to a lower number, for example 10.
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0

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0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
In the current zone designations, there are some zones where temperature differences would be significant due to their very large north/south
geographical spans. A concern arises whether the chosen extreme temperature event case is applicable to the overall zone in these cases. It might not
be representative of certain parts of the zone. Each Planning Coordinator, in conjunction with its Transmission Planner(s) shall select which extreme
heat and extreme cold weather events to develop benchmark extreme temperature events applicable to their region.
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0

Response
Bobbi Welch - Midcontinent ISO, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee (SRC) Project 2023-07 TPL-008-1 Draft #3
Answer
Document Name
Comment

No

The ISO/RTO Council (IRC) Standards Review Committee (SRC)[1] supports the intent of Requirement R2, i.e., to provide Planning Coordinators
(PCs) with the option of selecting a benchmark temperature event from the ERO library or the ability to develop one or more benchmark temperature
events on their own. If the PC(s) select an event from either the ERO library, the ERO is responsible for providing data in support of Parts 2.1 and 2.2.
Alternatively, if the PC(s) elects to develop a benchmark temperature event, the PC(s) is responsible for providing data in support of Parts 2.1 and 2.2.
Therefore, the SRC proposes the following modification to clarify the intent of Requirement R2:
R2. Each Planning Coordinator shall identify the zone(s) to which the Planning Coordinator belongs to under Attachment 1, and shall coordinate with all
Planning Coordinators within each of its identified zone(s), to select one common extreme heat benchmark temperature event and one common
extreme cold benchmark temperature event from either the benchmark library developed, approved and maintained by the Electric Reliability
Organization (ERO) or elect to develop one or both common benchmark temperature event(s) for each of its identified zone(s) when completing
the Extreme Temperature Assessment.1 Each benchmark temperature event shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
The SRC recommends that Part 2.2 be revised as follows to clarify the link between Part 2.2 and Part 2.1: “Represent one of the 20 most extreme
temperature conditions within the period identified in Part 2.1 based on the three-day rolling average…”
The SRC recommends that footnote 1 be revised to clarify that the ERO library may not contain all valid benchmark temperature events as Planning
Coordinators are free to develop their own benchmark temperature events: “The Electric Reliability Organization (ERO) will maintain a library of the
benchmark temperature events developed by the ERO that meet the criteria of Requirement R2, inclusive of Parts 2.1 and 2.2.”
The SRC also requests that the drafting team clarify how the event temperature information (available on NERC’s website) is intended to be used, and
more specifically, whether it is to be applied across the entire zone.
[1] For purposes of these comments, the IRC SRC includes the following entities: IESO, ISO-NE, MISO, NYISO (except for a portion of our response to
question 3 as noted in our response to question 3), PJM and SPP.
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Joseph Knight - Joseph Knight On Behalf of: Jacalynn Bentz, Great River Energy, 3, 1, 5, 6; - Joseph Knight
Answer

No

Document Name
Comment
Requirement R2 and R3 following R1 creates confusion when reading the responsibilities of requirements 4-11. Consider reordering – R2, R3 then
R1. Coordinating Zones, develop benchmark planning then conducting the assessments. The Transmission Planner (TP) is not referenced in R2 or
R3.

R2 currently – Coordinating Zones
Each Planning Coordinator shall identify the zone(s) to which the Planning Coordinator belongs to under Attachment 1, and shall coordinate with all
Planning Coordinators within each of its identified zone(s), to select one common extreme heat benchmark temperature event and one common
extreme cold benchmark temperature event for each of its identified zone(s) when completing the Extreme Temperature Assessment.

R3 currently – a process for developing benchmark planning
Each Planning Coordinator shall coordinate with all Planning Coordinators within each of its zone(s) identified in Requirement R2, to implement a
process for developing benchmark planning cases for the Extreme Temperature Assessment that represent the benchmark temperature events
selected in Requirement R2 and sensitivity cases to demonstrate the impact of changes to the basic assumptions used in the benchmark planning
cases.

R1 currently – The assessments
Each Planning Coordinator shall identify, in conjunction with its Transmission Planner(s), each entity’s individual and joint responsibilities for completing
the Extreme Temperature Assessment, which shall include each of the responsibilities described in Requirements R2 through R11. Each responsible
entity shall complete its responsibilities such that the Extreme Temperature Assessment is completed at least once every five calendar years.

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0

Response
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer

No

Document Name
Comment
Ameren believes the language in sections 2.1 and 2.2 are too prescriptive. We believe the Planning Coordinator should work with stakeholders to
determine the data set that will be used to derive extreme heat and cold weather temperatures. Does the planning coordinator have the ability to carve
the zones?
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0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Junji Yamaguchi, Hydro-Quebec (HQ), 1, 5; Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal
Mazza
Answer
Document Name
Comment

No

We support Independent Electricity System Operator’s and NB Power Corporation comments.
Furthermore, our understanding of the Benchmark Process is that the Weather Zones were used to develop the lists (library) of Benchmark Events, and
therefore each Weather Zone has its library. Our interpretation of the current document would be that Québec shares the same library "Eastern
Canada" as our Canadian neighbors, without however having to choose the same events every 5 years because we are alone in our ETA Zone as per
the table in Attachment 1.
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Response
Michael Brytowski - Great River Energy - 3
Answer

No

Document Name
Comment
Requirement R2 and R3 following R1 creates confusion when reading the responsibilities of requirements 4-11. Consider reordering – R2, R3 then
R1. Coordinating Zones, develop benchmark planning then conducting the assessments. The Transmission Planner (TP) is not referenced in R2 or
R3.
R2 currently – Coordinating Zones
Each Planning Coordinator shall identify the zone(s) to which the Planning Coordinator belongs to under Attachment 1, and shall coordinate with all
Planning Coordinators within each of its identified zone(s), to select one common extreme heat benchmark temperature event and one common
extreme cold benchmark temperature event for each of its identified zone(s) when completing the Extreme Temperature Assessment.
R3 currently – a process for developing benchmark planning
Each Planning Coordinator shall coordinate with all Planning Coordinators within each of its zone(s) identified in Requirement R2, to implement a
process for developing benchmark planning cases for the Extreme Temperature Assessment that represent the benchmark temperature events
selected in Requirement R2 and sensitivity cases to demonstrate the impact of changes to the basic assumptions used in the benchmark planning
cases.
R1 currently – The assessments
Each Planning Coordinator shall identify, in conjunction with its Transmission Planner(s), each entity’s individual and joint responsibilities for completing
the Extreme Temperature Assessment, which shall include each of the responsibilities described in Requirements R2 through R11. Each responsible
entity shall complete its responsibilities such that the Extreme Temperature Assessment is completed at least once every five calendar years.
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1

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Scott Brame, N/A, Brame Scott
0

Jennie Wike - Jennie Wike On Behalf of: Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; John Merrell, Tacoma Public Utilities
(Tacoma, WA), 1, 4, 5, 6, 3; John Nierenberg, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; Ozan Ferrin, Tacoma Public Utilities (Tacoma,
WA), 1, 4, 5, 6, 3; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; - Jennie Wike, Group Name Tacoma Power
Answer

No

Document Name
Comment
Tacoma Power is concerned that there may be circumstances where not all Planning Coordinators in a zone will agree to one common cold and heat
event. Instead of using “all Planning Coordinators” in the R2 Requirement language, Tacoma Power recommends using “majority of Planning
Coordinators”, as shown in the mark-up below.
Tacoma Power also recommends the following changes to the R2 language. This change makes it clear that there’s two distinct steps to this
Requirement: 1) identifying the zone(s) and then 2) selecting two common events for all PCs in that zone.
“Each Planning Coordinator shall identify the zone(s) to which the Planning Coordinator belongs to under Attachment 1. The majority of Planning
Coordinators within each of its identified zone(s) shall select one common extreme heat benchmark temperature event and one common extreme
cold benchmark temperature event for each of its identified zone(s) when completing the Extreme Temperature Assessment.”
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Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
Dominion Energy supports EEI comments
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0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer
Document Name
Comment
Please see comments for Question 1.

No

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Response
Erin Wilson - NB Power Corporation - New Brunswick Power Transmission Corporation - 5
Answer

No

Document Name
Comment
Please see comments for Question 1
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0

Response
Mark Flanary - Midwest Reliability Organization - 10
Answer

No

Document Name
Comment
In the current zone designations, there are some zones where temperature differences would be significant due to their very large north/south
geographical spans. A concern arises whether the chosen extreme temperature event case is applicable to the overall zone in these cases. It might not
be representative of certain parts of the zone.
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0

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0

Response
Donald Lock - Talen Generation, LLC - 5
Answer
Document Name
Comment

No

It is inadequate for TPL-008 and for all NERC cold weather-related standards to select. just one cold weather benchmark, based exclusively on
temperature. Several scenarios must be studied, covering the vulnerabilities of the various generation plant types – extreme cold plus high wind for
conventional facilities, ice storms and wind droughts for wind turbines, nighttime and snow coverage for solar farms.
The best benchmarks are “perfect storm” combination events. What made Winter Storm Uri so destructive, for example, was that it began with an ice
storm that took-out the wind fleet of northern Texas, followed by a deep freeze with high winds that tripped many conventional plants, then a wind
drought that prevented the now-deiced wind turbines from helping.
The lookback period should be 50 years, to coincide with the 50-year periodicity data published by ASHRAE. NERC should in general make more use
of ASHRAE data, to avoid making entities develop databases that are already available as a look-up.
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Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

No

Document Name
Comment
The Attachment 1 graphic would greatly benefit from including state boundaries, as well as mentioning the NERC benchmark library. Additionally,
clarification added that entities may select events that meet these criteria, either from the library or as identified by the group of Coordinators. Please
emphasize this flexibility of choice - it is likely to be lost in time.
NERC's consultant uses BA load weighting (based on notes and conversations provided in the 9/10 TPL-008 presentation). As a result, this weighting
practice does not appear to directly meet this proposed R2.2 language regarding the most extreme events for a region. The temperature may not
actually be representative of “across the zone” because of this weighting. Of reliability considerations, load is certainly part of the need, but potential
impacts to generation and the connecting transmission, which may be in other regions, are also important pieces to the delivery of resource to
load. Removal or modification of this R2 ‘most extreme’ language is recommended; or exempting the NERC library from needing to follow these
criteria. Alternately, the SDT may modify to allow weighting to be used in method.
Because the NERC Extreme Weather Event library is only updated every 3 years in the current plan, it is possible that an event in the library would
contain events that would not meet these R2 criteria for event “freshness”. The SDT may wish to consider modifying the language regarding time, or an
additional clause, to permit events currently in the NERC Extreme Weather Event library to not be subject to the selection criteria currently in R2, or that
entities may use the other criteria to evaluate and select other events.
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0

Response
Michele Tondalo - United Illuminating Co. - 1
Answer

No

Document Name
Comment
The intent of the standard is to perform an extreme temperature assessment, but R2 allows for selection from the “20 most extreme” events from a
period of 40 years. This could result in an entity being able to select an event that is relatively mild but still maintain compliance. This could be mitigated
by narrowing the number of extreme events to select from down to a lower number, for example 10.
Likes

0

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0

Response
Robert Blackney - Edison International - Southern California Edison Company - 1
Answer

Yes

Document Name
Comment
See comments submitted by Edison Electric Institute.
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0

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0

Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
ERCOT agrees with the updates to Requirement R2, and proposes the following clarifications based on ERCOT’s understanding of the intent and
function of Requirement R2.
- To better reflect the role that the Planning Coordinator’s selection plays in Parts 2.1 and 2.2, ERCOT recommends that the last sentence of the first
paragraph of Requirement R2 be revised to read “The Planning Coordinator’s selection of benchmark temperature events shall:”
- ERCOT recommends that Part 2.2 be revised as follows to clarify the link between Part 2.2 and Part 2.1: “Represent one of the 20 most extreme
temperature conditions within the period identified in Part 2.1 based on the three-day rolling average…”
- ERCOT recommends that footnote 1 either be removed or revised as follows to clarify that the ERO library might not contain all valid benchmark
temperature events, as Planning Coordinators are free to select benchmark temperature events that meet the criteria of Requirement R2 even if those
events are not in the ERO library: “The Electric Reliability Organization (ERO) will maintain a library of some, but not necessarily all, of the
benchmark temperature events that meet the criteria of Requirement R2.”

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Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

Yes

Document Name
Comment
ITC supports the proposed changes made to Requirement R2.
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0

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0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

Yes

Document Name
Comment
See EEI Comments
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0

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0

Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer

Yes

Document Name
Comment
WECC voted Affirmative for TPL-008 due to the timelines imposed on NERC by FERC. However, WECC still has some comments for the DT to
consider. WECC is concerned that the proposed language for R2 may be unclear. WECC understands that the intent of R2 is to allow PCs the option of
selecting a benchmark temperature event f rom the ERO library OR the ability to develop one or more benchmark temperature events based on their
own experiences. If a PC selects an event fromt he ERO library, the EOR would be responsible for providing supporting data. However, if the PC elects

to develop a benchmark temmperature event, the PC would be responsible for providing supproing data. If our understanding is corret, WECC suggests
the following modifications for clarity in R2:
Each Planning Coordinator shall identify the zone(s) to which the Planning Coordinator belongs to under Attachment 1, and shall coordinate with all
Planning Coordinators within each of its identified zone(s), to select one common extreme heat benchmark temperature event and one common
extreme cold benchmark temperature event from the benchmark library approved and maintained by the Electric Reliability Organization (ERO)
or elect to develop one or both common benchmark temperature event(s) for each of its identified zone(s) when completing the Extreme
Temperature Assessment.1 Selected Each benchmark temperature events shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
Additionally, it is WECC's understanding that a Minimum of one of each type of benchmark temperature event is required to be seleted. As written, the
requirement seems to indicate that only one may be seleted. It a minimum of one of each type is necessary, WECC suggests that the words "at least"
be added back to the requirement. If accepted this would need to be reflected in the Measure and VSLs as well.
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0

Response
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer

Yes

Document Name
Comment
See EEI Comments
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0

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0

Response
Kinte Whitehead - Exelon - 3
Answer

Yes

Document Name
Comment
Exelon agrees with the updated proposed TPL-008 Reliability Standard Requirement R2.
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0

Dislikes
Response

0

Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
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0

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0

Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI supports the proposed changes made to Requirement R2.
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0

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0

Response
Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer

Yes

Document Name
Comment
PNMR supports R2.
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0

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0

Response
Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon agrees with the updated proposed TPL-008 Reliability Standard Requirement R2.
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0

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0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

Yes

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Midwest Reliability Organization's NERC Standards Review Forum (MRO NSRF)
on question 2
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0

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0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
None.
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0

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0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer
Document Name

Yes

Comment
SNPD supports the zones outlined in the map provided in Attachment 1. However, the graphic would be significantly improved by incorporating state
boundaries and referencing the NERC benchmark library.
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0

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0

Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

Yes

Document Name
Comment
Manitoba Hydro supports the intent of R2, where PC identifies common extreme heat and extreme cold weather events applicable to its zone. However,
Manitoba Hydro recommends that PCs be given the option to select such events from the ERO-maintained benchmark event list or use their own
experience to develop benchmark extreme temperature events applicable to their region.
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0

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0

Response
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

Yes

Document Name
Comment
The MRO NSRF supports the intent of Requirement R2; however, believes the proposed language as currently written is unclear. Our understanding is
the intent of R2 is to provide Planning Coordinators (PCs) with the option of selecting a benchmark temperature event from the ERO library or the ability
to develop one or both benchmark temperature events on their own. If the PC(s) select an event from the ERO library, the ERO is responsible for
providing data in support of Parts 2.1 and 2.2. Alternatively, if the PC(s) elects to develop a benchmark temperature event, the PC(s) is responsible for
providing data in support of Parts 2.1 and 2.2. Therefore, the MRO NSRF proposes the following modification to clarify the intent of Requirement R2:

R2. Each Planning Coordinator shall identify the zone(s) to which the Planning Coordinator belongs to under Attachment 1, and shall coordinate with all
Planning Coordinators within each of its identified zone(s), to select one common extreme heat benchmark temperature event and one common
extreme cold benchmark temperature event from the benchmark library approved and maintained by the Electric Reliability Organization (ERO)
or elect to develop one or both common benchmark temperature event(s) for each of its identified zone(s) when completing the Extreme
Temperature Assessment. Each benchmark temperature events shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]

Likes

0

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0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
Comment
FirstEnergy has no comments toward R2.
Likes

0

Dislikes

0

Response
Ben Hammer - Western Area Power Administration - 1
Answer

Yes

Document Name
Comment
The proposed R2 language as currently written is unclear. Our understanding is the intent of R2 is to provide Planning Coordinators (PCs) with the
option of selecting a benchmark temperature event from the ERO library or the ability to develop one or both benchmark temperature events on their
own. If the PC(s) select an event from the ERO library, the ERO is responsible for providing data in support of Parts 2.1 and 2.2. Alternatively, if the
PC(s) elects to develop a benchmark temperature event, the PC(s) is responsible for providing data in support of Parts 2.1 and 2.2. Therefore, we
proposes the following modification to clarify the intent of Requirement R2:
R2. Each Planning Coordinator shall identify the zone(s) to which the Planning Coordinator belongs to under Attachment 1, and shall coordinate with all
Planning Coordinators within each of its identified zone(s), to select one common extreme heat benchmark temperature event and one common
extreme cold benchmark temperature event from the benchmark library approved and maintained by the Electric Reliability Organization (ERO) or elect
to develop one or both common benchmark temperature event(s) for each of its identified zone(s) when completing the Extreme Temperature
Assessment. Each benchmark temperature event shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
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Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
AEP agrees with the changes made to R2, but requests that content be added to make it clear that usage of the ERO-maintained library of benchmark
temperature events is optional.
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Greg Sorenson - Greg Sorenson On Behalf of: Tremayne Brown, ReliabilityFirst , 10; - ReliabilityFirst - 10 - RF
Answer

Yes

Document Name
Comment
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Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
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Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Document Name
Comment

Yes

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Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

Yes

Document Name
Comment
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Joshua London - Eversource Energy - 1, Group Name Eversource
Answer

Yes

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Comment
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Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

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Comment
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Sharon Darwin - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC

Answer

Yes

Document Name
Comment
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Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

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Comment
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Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

Yes

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Comment
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Ronald Hoover - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

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Comment
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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
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Helen Lainis - Independent Electricity System Operator - 2
Answer

Yes

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Comment
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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

Yes

Document Name
Comment
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Srikanth Chennupati - Entergy - 1,3,5,7 - SERC
Answer

Yes

Document Name
Comment
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Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
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Kevin Conway - Western Power Pool - 4
Answer

Yes

Document Name
Comment
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Robert Follini - Avista - Avista Corporation - 3
Answer

Yes

Document Name
Comment
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Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer

Yes

Document Name
Comment
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Robert Jones - Seattle City Light - 1,3,4,5,6
Answer
Document Name
Comment
We agree with the plan, although there should be some method to help ensure coordination on scenario selection and case data submittal among all
PCs in a zone. How will disagreements among PC's be resolved? Voting? Regions can probably resolve this on their own most of the time, but there
may be disputes that need to be resolved somehow.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE noticed the Technical Rationale states that “Requirement R2 does not preclude entities from collecting collect temperature data and
identifying benchmark temperature events through their own processes”. Texas RE recommends Footnote 1 acknowledge this and recommends the
following revision (in bold):

“The Electric Reliability Organization (ERO) will maintain a library of benchmark temperature events that meet the criteria of Requirement R2. Planning
Coordinator(s) may identify their own benchmark temperature events provided the selected benchmark meet R2 criteria and the Planning
Coordinator provides evidence of technical justification.”

Since the periodicity of extreme heat and cold events are increasing in the recent years and the trend may continue to show strongest increase in
extremes. The selected benchmark temperature event shall include all the extreme events closest to the benchmark selection process. Consider
changing the requirement in 2.1 to include ‘temperature data ending no more than two years prior to the time the benchmark temperature events are
selected”. Texas RE recommends the following revision (in bold):

2.1. Consider no less than a 40-year period of temperature data ending no more than two years prior to the time the benchmark temperature events are
selected; and
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0

3. The DT updated Requirements R3 – R4 based on comments received. Do you agree with the updated proposed TPL-008-1 Reliability
Standard Requirements? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural justification.
Devin Shines – LG&E/KU
Answer

Yes

Document Name
Comment
LG&E/KU agrees with the modifications in Requirements R3 and R4. These changes adequately balance the need for transparency, practicality, and
effectiveness.
LG&E/KU would request the DT consider whether Requirement R3 and its VSLs could be modified to address the situation where one (or more)
Planning Coordinators in a zone does not coordinate. As-is, the Requirement R3 language could be understood as all other PCs in that zone also
being out of compliance.
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Ben Hammer - Western Area Power Administration - 1
Answer

No

Document Name
Comment
Requirement R3: The prior draft of TPL-008 contained language in R3 that required “Planning Coordinator(s), Transmission Planner(s), and other
designated study entities” to collectively implement the requirement. We request language along these lines be reinstated such that all parties that play
a role in implementing the process for developing benchmark planning cases must comply. Our suggested language modification below:
R3. Each Planning Coordinator shall coordinate with all Planning Coordinators and each responsible entity (identified in Requirement R1) within each of
its zone(s) identified in Requirement R2, to implement a process for developing benchmark planning cases…
Note: If adopted, the Technical Rationale for R3 will also need to be updated to reflect this change.
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Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD

Answer

No

Document Name
Comment
In FERC Order 896, paragraph 39, there is a Commission Determination as follows:
“We also direct NERC to include in the Reliability Standard the framework and criteria that responsible entities shall use to develop from the relevant
benchmark event planning cases to represent potential weather-related contingencies (e.g., concurrent/correlated generation and transmission outages,
derates) and expected future conditions of the system such as changes in load, transfers, and generation resource mix, and impacts on generators
sensitive to extreme heat or cold, due to the weather conditions indicated in the benchmark events. Developing such a framework would provide a
common design basis for responsible entities to follow when creating benchmark planning cases. This would not only help establish a clear set of
expectations for responsible entities to follow when developing benchmark planning events, but also facilitate auditing and enforcement of the
Standard.”
In review of Order 896, we find the term “contingencies” is used two different ways. Paragraph 39 describes things that are in the base or N-0 state –
for example, a cold weather event occurs, and certain wind generators can no longer operate – this as a base contingency. Similarly, in paragraph 88,
there is an additional Commission Determination as follows, in further support of these baseline “contingency” outages:
“Pursuant to section 215(d)(5) of the FPA, we adopt the NOPR proposal and direct NERC to require under the new or revised Reliability Standard the
study of concurrent/correlated generator and transmission outages due to extreme heat and cold events in benchmark events as described in more
detail below.”
Then later, in Paragraph 92 (still under the Commission Determination), FERC further clarifies:
“Regarding the comments of NYISO and EPRI on the difference between extreme events and contingencies covered under Reliability Standard TPL001-5.1, we clarify that all contingencies included in benchmark planning cases under the new or modified Reliability Standard will represent initial
conditions for extreme weather event planning and analysis. These contingencies (i.e., correlated/concurrent, temperature sensitive outages, and
derates) shall be identified based on similar contingencies that occurred in recent extreme weather events or expected to occur in future forecasted
events.”
From these, it is clear that Order 896 is expecting “contingencies” of weather-based equipment outages to be part of the base or N-0 system state. The
more traditional “contingencies” are then addressed on top of this condition, as presented in Order 896, Section G, starting at Paragraph 95.
The specific request from this comment is for the SDT to clarify how it expects such base “contingencies” to be included in the model. There does not
appear to be language currently in the standard in support of this, and it is clear from Order 896 that it is expected both the base model outage
“contingencies” and then subsequent contingency events to test system performance.
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Donald Lock - Talen Generation, LLC - 5
Answer
Document Name
Comment

No

Once again, focusing exclusively on dry bulb temperature is inadequate for TPL-008 and for all NERC winter weather-related standards. Ref. R3.2 for
example, there are no simple and reliable, “[dry bulb] temperature dependent adjustments for Load.” A wind chill basis is needed. Mistakenly assuming
that load tracks the DBT is why some ISOs severely under-predicted the peak load for Winter Storm Elliott, which was only moderately cold but had
extremely strong winds.
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Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

No

Document Name
Comment
Requirement R3: The prior draft of TPL-008 contained language in R3 that required “Planning Coordinator(s), Transmission Planner(s), and other
designated study entities” to collectively implement the requirement. The MRO NSRF requests language along these lines be reinstated such that all
parties that play a role in implementing the process for developing benchmark planning cases must comply. Our suggested language modification
below:

R3. Each Planning Coordinator shall coordinate with all Planning Coordinators and each responsible entity (identified in Requirement R1) within
each of its zone(s) identified in Requirement R2, to implement a process for developing benchmark planning cases…

Note: If adopted, the Technical Rationale for R3 will also need to be updated to reflect this change.
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Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
Dominion Energy supports EEI comments
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Response
Jennie Wike - Jennie Wike On Behalf of: Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; John Merrell, Tacoma Public Utilities
(Tacoma, WA), 1, 4, 5, 6, 3; John Nierenberg, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; Ozan Ferrin, Tacoma Public Utilities (Tacoma,
WA), 1, 4, 5, 6, 3; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; - Jennie Wike, Group Name Tacoma Power
Answer

No

Document Name
Comment
Tacoma Power is concerned that there may be circumstances where not all Planning Coordinators in a zone will agree to one common cold and heat
event. Instead of using “all Planning Coordinators” in the R3 Requirement language, Tacoma Power recommends using “majority of Planning
Coordinators”, as shown in the mark-up below.
“Each Planning Coordinator shall coordinate with the majority of the Planning Coordinators within each of its zone(s) identified in Requirement R2, to
implement a process for developing benchmark planning cases for the Extreme Temperature Assessment that represent the benchmark temperature
events selected in Requirement R2 and sensitivity cases to demonstrate the impact of changes to the basic assumptions used in the benchmark
planning cases.”
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Joshua London - Eversource Energy - 1, Group Name Eversource
Answer

No

Document Name
Comment
Eversource recommends reinserting from Draft 2 the Transmission Planner as part of the coordination in R3:

Each Planning Coordinator shall coordinate with all Planning Coordinators and Transmission Planners within each of its zone(s)…
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Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer

No

Document Name
Comment
Ameren would like more clarification around R3 sections 3.2 and 3.3. Will MOD-032 be revised to include extreme temperature data?
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Joseph Knight - Joseph Knight On Behalf of: Jacalynn Bentz, Great River Energy, 3, 1, 5, 6; - Joseph Knight
Answer

No

Document Name
Comment
GRE supports the comments of the NSRF and GRE has additional comments
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Response
Bobbi Welch - Midcontinent ISO, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee (SRC) Project 2023-07 TPL-008-1 Draft #3
Answer

No

Document Name
Comment
Requirement R3: The prior draft of TPL-008 contained language in R3 that required “Planning Coordinator(s), Transmission Planner(s), and other
designated study entities” to collectively implement the requirement. The SRC requests language along these lines be reinstated such that all parties
that play a role in implementing the process for developing benchmark planning cases must comply. Our suggested language modification below:
R3. Each Planning Coordinator shall coordinate with all Planning Coordinators and each responsible entity (identified in Requirement R1) within
each of its zone(s) identified in Requirement R2, to implement a process for developing benchmark planning cases…
Note: If adopted, the Technical Rationale for R3 will also need to be updated to reflect this change.
In addition, the SRC[1] is concerned that Requirement R3 unnecessarily and inadvertently limits the ability of entities to properly develop their
benchmark planning cases. Specifically, the SRC is concerned that R3 could be understood to mean that entities are limited to making the adjustments
specifically described in R3 and are prevented from making adjustments necessary to update the planning cases to reflect the expected future state of
the system or to ensure that the generation necessary to serve load is available so that the case can solve. As the drafting team recognizes in the
Technical Rationale, adjusting the case to ensure that it contains enough generation to serve the modeled load is essential to ensure that the standard

does not stray into the realm of resource adequacy issues and fully complies with paragraph 94 of FERC Order No. 896, which states that resource
adequacy is not in scope for this project.
To address this, the SRC recommends that the drafting team renumber the current Part 3.4 to Part 3.5 and add a new Part 3.4 that reads as follows:
“3.4. Adjustments to the total modeled generation or Load in each case as necessary to allow the total modeled generation to serve the total modeled
System Load.”
The SRC also recommends that Requirement R4 be revised as needed to align with any revisions made to Requirement R3.
Requirement R4: FERC Order 896 paragraph 154 is clear that FERC does not intend to order the construction of new transmission facilities through
this standard. However, due to the inherently extreme nature of these contingency scenarios, Corrective Action Plans will likely have to include facility
upgrades that would not have been needed under current system design criteria under TPL-001-5.1. Since TPL-001-5.1 studies are conducted
annually, and ISO/RTOs have processes outside NERC standards to identify transmission expansion projects that may be identified before the next 5year TPL-008 study period, we recommend TPL-008 be revised to allow the CAPs to be updated as determined by the PC, thereby accommodating
regional planning solutions to mitigate deficiencies identified under TPL-008 without having to wait 5 years for the next TPL-008 study cycle or conduct
a completely new series of TPL-008 studies to update the CAP.
Requirement R3.4: We recommend the SDT consider updating R3.4 or the Technical Rationale to include broader system conditions for sensitivity
studies, as the conditions for the sensitivity cases seem to be focused on steady state analysis when there could be other assumptions to consider that
affect system dynamic performance, for example, dynamic load models, DER dynamics, etc.
[1] NYISO abstains from this comment and the associated proposed revision to Part 3.4.
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Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy Houston Electric, LLC (CEHE) does not agree sensitivity case requirements are needed as these place an unnecessary burden on
Entities with little reliability benefit. CEHE recommends the removal of Requirement R4.2 in order to agree with Requirements R3 and R4 as written.
FERC Order 896 is expecting “contingencies” of weather-based equipment outages to be part of the base or N-0 system state. The more traditional
“contingencies” are then addressed on top of this condition, as presented in Order 896, Section G, starting at Paragraph 95. CEHE recommends for the
SDT to clarify how it expects such base “contingencies” to be included in the model. There does not appear to be language currently in the standard in
support of this, and it is clear from Order 896 that it is expected both the base model outage “contingencies” and then subsequent contingency events
test system performance.

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Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer

No

Document Name
Comment
See comment to question 2, If "at least" one of each type of benchmark temperature event is required, Parts 4.1 and 4.2 would need to be modified to
reflect this.
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Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
There are no issues with R3. The SDT should consider removing R4.2, since the assessment already covers multiple extreme weather
scenarios. There is questionable reliability benefit in running additional sensitivities that do not rise to the level of requiring (or eliminating) corrective
actions.
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Greg Sorenson - Greg Sorenson On Behalf of: Tremayne Brown, ReliabilityFirst , 10; - ReliabilityFirst - 10 - RF
Answer

No

Document Name
Comment
10 year cases may not be the most appropriate for identification of binding improvements as estimates of generation additions and retirements and load
additions are still developing. Five year cases should provide sufficient detail to identify needed reliability improvements while still allowing time for
construction.
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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT is concerned that Requirement R3 unnecessarily and inadvertently limits the ability of entities to properly develop their benchmark planning
cases. Specifically, ERCOT is concerned that R3 could be understood to mean that entities are limited to making the adjustments specifically described
in R3 and are prevented from making adjustments necessary to ensure that the generation necessary to serve load is available so that the case can
solve. As the drafting team recognizes in the Technical Rationale, adjusting the case to ensure that it contains enough generation to serve the modeled
load is essential to ensure that the standard does not stray into the realm of resource adequacy issues and fully complies with paragraph 94 of FERC
Order No. 896, which states that resource adequacy is not in scope for this project.

To address this, ERCOT recommends that the drafting team revise Part 3.2 by replacing the period at the end of Part 3.2 with the following: “, provided
that the responsible entity may adjust the total modeled generation or Load in each case as necessary to allow the total modeled generation to serve
the total modeled System Load.”

ERCOT also recommends that Requirement R4 be revised as needed to align with any revisions made to Requirement R3.
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Response
Michael Goggin - Grid Strategies LLC - 5
Answer

No

Document Name
Comment
First, to comply with FERC Order 896, the standard should specify that benchmark events and Extreme Temperature Assessments will account for
concurrent/correlated outages of generators during extreme heat and cold events. In Order 896 paragraph 88, FERC directs “NERC to require under
the new or revised Reliability Standard the study of concurrent/correlated generator and transmission outages due to extreme heat and cold events in
benchmark events,” explaining in paragraph 89 that “it is necessary that responsible entities evaluate the risk of correlated or concurrent outages and
derates of all types of generation resources and transmission facilities as a result of extreme heat and cold events.”
The draft of TPL-008 R3 appears to put the burden on responsible entities and not NERC for accounting for correlated outages in making “seasonal and
temperature dependent adjustments for Load, generation, Transmission, and transfers” and conducting sensitivity analyses.

Having responsible entities and not NERC conduct this adjustment increases the risk that different regions will use inconsistent methods for doing so,
and at worst responsible entities that want to avoid addressing reliability concerns through a Corrective Action Plan will use unrealistically low
assumptions for the rate of correlated generator outages or other input assumptions like load and transfers. This assumption can have such a large
impact on results it cannot be left to responsible entities, and should be made by NERC. The drafting team’s Technical Rationale used similar logic in
deciding that NERC (the Electric Reliability Organization or ERO) should assemble the benchmark planning cases: “to ensure consistency across
regions, it is necessary for the ERO to have the responsibility for determining the suitability of benchmark events to represent probable future
conditions.”
Given the significant variation in the rates at which different fuel types experience correlated outages,[1] and rapid changes in the generation mix that
may cause the future power system to have greater or lesser exposure to correlated outage risk, it is particularly important for the benchmark events
and Extreme Temperature Assessments to account for the concurrent/correlated outage risk of each fuel type in the future generation mix. In recent
cold snap events, gas generator outages due to equipment failures and fuel supply interruptions have accounted for the majority of outages. NERC
GADS data can be used to assess the rate of correlated outages and derates of generators by fuel type.{C}[2]
Second, the benchmark cases and Extreme Temperature Assessments should account for changes to generation, demand, and transmission resulting
from climate change, electrification of heating, and other factors that are affecting the risk posed by extreme heat and cold. Accounting for how climate
change is increasing the frequency and magnitude of extreme heat and cold events is consistent with FERC’s Order 896 directive in paragraph 40: “We
also direct NERC to ensure the reliability standard contains appropriate mechanisms for ensuring the benchmark event reflects up-to-date
meteorological data. The increasing intensity, frequency, and unpredictability of extreme weather conditions requires that key aspects of the benchmark
events be reviewed, and if necessary, updated periodically to ensure the corresponding benchmark planning cases reflect updated meteorological
data.” Electrification of heating is also increasing the sensitivity of electricity demand to extreme cold conditions, which should be accounted for in the
benchmark cases and Extreme Temperature Assessments.
Third, due to the impact of climate change, electrification, and rapid changes in the generation mix, requirement R1 should require responsible entities
to complete an Extreme Temperature Assessment more frequently than at least once every five calendar years. As noted above, FERC Order 896
specifies that the meteorology underlying benchmark cases should be updated at least every five years, but the generation mix and other grid
conditions can change more rapidly than that. TPL-001 requirement R2 requires Planning Assessments to be conducted annually, and a similar annual
requirement for Extreme Temperature Assessments is appropriate given that extreme heat and cold events are the largest threat to electric reliability.

{C}[1]{C} See, e.g., FERC and NERC, Winter Storm Elliott Report: Inquiry into Bulk-Power System Operations During December 2022 (October 2023),
https://www.ferc.gov/media/winter-storm-elliott-report-inquiry-bulk-power-system-operations-during-december-2022, at 17; FERC and NERC, The
February 2021 Cold Weather Outages in Texas and the South Central United States (November 2021), https://www.ferc.gov/media/february-2021-coldweather-outages-texas-and-south-central-united-states-ferc-nerc-and, at 16; FERC and NERC, 2019 FERC and NERC Staff Report: The South Central
United States Cold Weather Bulk Electric System Event of January 17, 2018 (July 2019), https://www.ferc.gov/legal/staff-reports/2019/07-18-19-fercnerc-report.pdf; PJM, Analysis of Operational Events and Market Impacts During the January 2014 Cold Weather Events (May 2014),
https://www.pjm.com/~/media/library/reports-notices/weather-related/20140509-analysis-of-operational-events-and-market-impacts-during-the-jan-2014cold-weather-events.ashx.
{C}[2]{C} For example, see the analysis of GADS data provided in S. Murphy et al., Resource adequacy risks to the bulk power system in North America
(February 2018), https://www.sciencedirect.com/science/article/pii/S0306261917318202, with Supplementary Material including outage data available at
https://ars.els-cdn.com/content/image/1-s2.0-S0306261917318202-mmc1.zip
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Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle

Answer

No

Document Name
Comment
In R4, Extreme Temperature Events is already a “sensitivity” to the normal long-term planning cases. The cases will be built with
Gen/Load/Transmission/Transfer based on the extreme weather conditions. The need for sensitivity cases on top of “sensitivity cases” is not very
convincing.
Furthermore, the DT should explain if the sensitivity would be the same factor that one would modify or if you could change the sensitivity factor that you
modify. For example, let's say we have decided to adjust loads so that they're higher in the extreme heat sensitivity, but we wanted to pick transfer
levels with extreme cold. In R3.4 it is not specified if a different adjustment factor can be used for each one of the extreme cold/extreme heat sensitivity
cases or there is flexibility.
We request DT to add clarity to prevent misinterpretation, or for an auditor to step in and assign a restriction that's not there. We would prefer to see
R3.4 modified to say a different sensitivity, a different change can be made to the two different temperature cases or something that specifies you don't
have to use the same one.
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Response
Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
R3 and R4 appear duplicative in that they both involve the formation of study cases. R3 states “Implement a process for developing benchmark
planning cases” while R4 states “Use the coordination process… to develop the following… planning benchmark cases.”
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Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
Comment
FirstEnergy has no comments toward these requirement drafts.

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Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

Yes

Document Name
Comment
To improve the clarity of R3.4, it is recommended to consider updating R3.4, as shown below:
3.4. Identification of changes to at least one of the following conditions for sensitivity cases:
·

Generation additions, retirements. (it is not clear what is expected by just listing generation)

·

Real and reactive forecasted Load.

·

Expected transfers.

·
Expected in service dates of new or modified Transmission Facilities. (a new addition that Manitoba Hydro recommends to be included in the
sensitivity list)
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Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
None.
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0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples

Answer

Yes

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Midwest Reliability Organization's NERC Standards Review Forum (MRO NSRF)
on question 3
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Response
Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon agrees with the updated proposed TPL-008 Reliability Standard Requirements R3 and R4.
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0

Response
Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer

Yes

Document Name
Comment
PNMR supports R3 and R4.
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0

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0

Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name

Yes

Comment
EEI supports the proposed changes made to Requirements R3 and R4.
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0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
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0

Response
Kinte Whitehead - Exelon - 3
Answer

Yes

Document Name
Comment
Exelon agrees with the updated proposed TPL-008 Reliability Standard Requirements R3 and R4.
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Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Document Name
Comment

Yes

See EEI Comments
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0

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0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

Yes

Document Name
Comment
See EEI Comments
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0

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0

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Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

Yes

Document Name
Comment
ITC supports the proposed changes made to Requirements R3 and R4.
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0

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0

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Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
We understand and approve the proposed language in R3-R4. However, we recommend that the drafting team includes more clarity and benchmarks
for the process for sensitivity cases. The technical rationale currently does not include details as to how to develop or implement sensitivity cases.

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0

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Robert Blackney - Edison International - Southern California Edison Company - 1
Answer

Yes

Document Name
Comment
See comments submitted by Edison Electric Institute.
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0

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0

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Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer

Yes

Document Name
Comment
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0

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0

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Robert Follini - Avista - Avista Corporation - 3
Answer

Yes

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Comment
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0

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0

Kevin Conway - Western Power Pool - 4
Answer

Yes

Document Name
Comment
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0

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0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
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0

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0

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Michele Tondalo - United Illuminating Co. - 1
Answer

Yes

Document Name
Comment
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0

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0

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Srikanth Chennupati - Entergy - 1,3,5,7 - SERC
Answer
Document Name
Comment

Yes

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0

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0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

Yes

Document Name
Comment
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0

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0

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Mark Flanary - Midwest Reliability Organization - 10
Answer

Yes

Document Name
Comment
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0

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0

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Helen Lainis - Independent Electricity System Operator - 2

Answer

Yes

Document Name
Comment
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0

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0

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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
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0

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0

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Erin Wilson - NB Power Corporation - New Brunswick Power Transmission Corporation - 5
Answer

Yes

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Comment
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0

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0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Ronald Hoover - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
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0

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0

Response
Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

Yes

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Comment
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0

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0

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Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Robert Jones - Seattle City Light - 1,3,4,5,6
Answer

Yes

Document Name
Comment
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0

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0

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Sharon Darwin - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
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0

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0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
Comment
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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 NPCC RSC
Answer

Yes

Document Name
Comment
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0
0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

Yes

Document Name
Comment
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0

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0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
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0

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0

Response
Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

Yes

Document Name
Comment
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0

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0

Response
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Document Name

Yes

Comment
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0

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0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer

Yes

Document Name
Comment
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0

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0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE recommends defining “the zone” in Requirement Part R3.3. Texas RE recommends the following revision (in bold):

R3.3. Assumed seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers in areas outside the zone identified in Requirement R2, as needed.

Texas RE noticed that neither R3 nor R4 mention a requirement to include “concurrent” generator and transmission outages as noted in FERC Order
No. 896, which states: “…the impact of concurrent failures of Bulk-Power System generation and transmission equipment and the potential for
cascading outages that may be caused by extreme heat and cold weather events should be studied”. The Considerations of the Order document says
“Per Requirement R4, the data necessary to build the benchmark planning cases must be provided via MOD-032 and supplemented by other sources
as needed. Any concurrent/correlated generator and transmission outages due to extreme heat and cold events in benchmark temperature events
should be reflected in the model data and thus represented in the initial conditions of the benchmark planning cases.”
Based on the current Requirements R3 and R4 language, the cases could be built with high loads and high generation dispatch for the extreme weather
without including concurrent outages. Therefore, a requirement in R3 or R4 that specifically says to include “concurrent” generator and transmission
outages in the initial conditions of the benchmark planning cases needs to be added in accordance with the FERC Order. Also, the rationale for those
concurrent outages selected for the initial conditions shall be available as supporting information. Texas RE noticed that the Technical Rationale does
mention concurrent outages and recommends incorporating this language directly into the requirement language itself through the note described
below.

Requirement R4.2 also does not specify which system conditions should be varied to create sensitivity cases. Normally sensitivity studies are
conducted to identify system deficiencies under stressed system conditions such as generation changes, load variations, delays in implementing system
improvements, multiple system elements being unavailable due to extended outages, etc.

Texas RE recommends the following revisions to Requirement R4 and Requirement 4.2 to clarify the language, address concurrent outages, and clarify
the requirements for sensitivity cases:

R4. Each responsible entity, as identified in Requirement R1, shall use the coordination process developed in accordance with Requirement R3 and
data consistent with that provided in accordance with the MOD-032 standard, supplemented by other sources as needed, to develop the following
and establish category P0 as the normal System condition in Table 1 and develop and maintain the following:
4.2 One common extreme heat and one common extreme cold sensitivity case by varying one or more of the system conditions such as
forecasted load, generation dispatch, unavailability of multiple system elements (overlapping outages), etc. to stress the system sufficiently
to demonstrate measurable changes in system responses.

Texas RE further recommends adding the following as a note under Requirement 4:

Planning Coordinator shall use coincident peak load for extreme temperature assessments to more appropriately reflect load conditions during systemwide weather conditions. Transmission Planner(s) shall use the forecasted non-coincident peak load for evaluating its respective area assessments.
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4. The DT updated Requirements R7 – R8 based on comments received. Do you agree with the updated proposed TPL-008-1 Reliability
Standard Requirements? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural justification.
Devin Shines – LG&E/KU
Answer

Yes

Document Name
Comment
LG&E/KU agrees with the modifications in Requirements R7 and R8 (as well as those in Requirements R5 and R6 which do not have a dedicated
question on this comment form). These modifications improve the clarity of the standard.
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0

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0

Response

Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

No

Document Name
Comment
Please see PG&E’s comments in (Q3) for R4 as R8 is in reference to R4.
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0

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0

Response
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer

No

Document Name
Comment
SPP has identified an inconsistency between the proposed requirement language and the technical rationale. The technical rationale denotes the
expectation to run at a minimum P0, P1, P7 whereas the language in the requirement states “Contingencies for each category in Table 1 that are

expected to produce more severe System impacts”. This indicates a compliance obligation to produce a contingency list for the entire table instead of
only those in the P0, P1, P7 categories as stated in the technical rationale.
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0

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0

Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
Regarding R8, it is unclear if the responsible entity must identify continencies for each event type shown within each category, or only those event types
that are expected to produce more severe System impacts on its portion of the Bulk Electric System
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0

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0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CEHE does not agree with sensitivity cases in Extreme Temperature Assessments for the same reasons as mentioned in Q3. CEHE recommends the
removal of 8.2 in order to agree with Requirements R7 and R8.
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0

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0

Response
Joseph Knight - Joseph Knight On Behalf of: Jacalynn Bentz, Great River Energy, 3, 1, 5, 6; - Joseph Knight
Answer
Document Name
Comment

No

GRE supports the comments of the NSRF and GRE has additional comments
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0

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0

Response
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

No

Document Name
Comment
The steady state contingencies do not necessarily apply for transient stability. The transient stability contingencies are a subset of the steady-state
contingencies.
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0

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0

Response
Robert Blackney - Edison International - Southern California Edison Company - 1
Answer

Yes

Document Name
Comment
See comments submitted by Edison Electric Institute.
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0

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0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

Yes

Document Name
Comment
ITC is supportive of the proposed changes made to Requirements R7 and R8.

Likes

0

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0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

Yes

Document Name
Comment
See EEI Comments
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0

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0

Response
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer

Yes

Document Name
Comment
See EEI Comments
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0

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0

Response
Kinte Whitehead - Exelon - 3
Answer

Yes

Document Name
Comment
Exelon agrees with the updated proposed TPL-008 Reliability Standard Requirements R7 and R8.

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0

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0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
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0

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0

Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI is supportive of the proposed changes made to Requirements R7 and R8.
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0

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0

Response
Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer

Yes

Document Name
Comment
PNMR supports R7 and R8.
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0

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0

Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon agrees with the updated proposed TPL-008 Reliability Standard Requirements R7 and R8.
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0

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0

Response
Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

Yes

Document Name
Comment
Requirement # 7 states:
“Each responsible entity, as identified in Requirement R1, shall identify the Contingencies for each category in Table 1 that are expected to produce
more severe System impacts on its portion of the Bulk Electric System. The rationale for those Contingencies selected for evaluation shall be available
as supporting information.”
Questions to the SDT for clarification: Is the intent is that the entity must identify contingencies for each contingency Event (such as P1.1, P1.2, P7.2 for
example) – or must have a rationale why certain events (such as P7.2 for example) are not the more severe? Without clarification, this requirement
could be interpreted differently by auditors.
Additionally, we interpret that the BES Contingency voltage level of >= 200 kV is meant to be a filter or screening criteria for identifying events that must
be considered and that would have a more severe impact on the BES. We also interpret that as part of the Extreme Temperature Assessment, an entity
is responsible for monitoring their entire BES.
Is this interpretation correct? Some elaboration on the 200 kV threshold within the Technical Rationale would be helpful.
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Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name

Yes

Comment
R8: For Table 1 – Steady State & Stability Performance Events, #6, please explain the rationale for stating the requirements for CAP’s in Footnote 6
rather than in Requirement 9.
R9: Organization of Footnote 6 is confusing because it is written with Requirement-like language that should reside in R9 itself.
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0

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0

Response
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

Yes

Document Name
Comment
n/a
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0

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0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
Comment
FirstEnergy has no comments toward these requirement drafts.
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0

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0

Response
Thomas Foltz - AEP - 5
Answer
Document Name

Yes

Comment
Please see AEP’s response to Question #7 which includes references to R8.
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0

Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
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0

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0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
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0

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0

Response
Greg Sorenson - Greg Sorenson On Behalf of: Tremayne Brown, ReliabilityFirst , 10; - ReliabilityFirst - 10 - RF
Answer

Yes

Document Name
Comment
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0
0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment
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0

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0

Response
Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

Yes

Document Name
Comment
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0

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0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Document Name

Yes

Comment
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0

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0

Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer

Yes

Document Name
Comment
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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 NPCC RSC
Answer

Yes

Document Name
Comment
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0

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0

Response
Bobbi Welch - Midcontinent ISO, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee (SRC) Project 2023-07 TPL-008-1 Draft #3
Answer

Yes

Document Name
Comment
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0

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0

Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer

Yes

Document Name
Comment
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0

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0

Response
Joshua London - Eversource Energy - 1, Group Name Eversource
Answer

Yes

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Comment
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0

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0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Jennie Wike - Jennie Wike On Behalf of: Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; John Merrell, Tacoma Public Utilities
(Tacoma, WA), 1, 4, 5, 6, 3; John Nierenberg, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; Ozan Ferrin, Tacoma Public Utilities (Tacoma,
WA), 1, 4, 5, 6, 3; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; - Jennie Wike, Group Name Tacoma Power
Answer
Document Name

Yes

Comment
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0

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0

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Sharon Darwin - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
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0

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0

Response
Robert Jones - Seattle City Light - 1,3,4,5,6
Answer

Yes

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Comment
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0

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0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

Yes

Document Name
Comment
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0
0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Ronald Hoover - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
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0

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0

Response
Jeffrey Streifling - NB Power Corporation - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Erin Wilson - NB Power Corporation - New Brunswick Power Transmission Corporation - 5
Answer
Document Name

Yes

Comment
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0

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0

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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
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0

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0

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Helen Lainis - Independent Electricity System Operator - 2
Answer

Yes

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Comment
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0

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0

Response
Mark Flanary - Midwest Reliability Organization - 10
Answer

Yes

Document Name
Comment
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0

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0

Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

Yes

Document Name
Comment
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0

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0

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Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

Yes

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Comment
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0

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0

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Srikanth Chennupati - Entergy - 1,3,5,7 - SERC
Answer

Yes

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Comment
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0

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0

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Donald Lock - Talen Generation, LLC - 5
Answer
Document Name
Comment

Yes

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0

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0

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Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

Yes

Document Name
Comment
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0

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0

Response
Ben Hammer - Western Area Power Administration - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Michele Tondalo - United Illuminating Co. - 1
Answer

Yes

Document Name
Comment
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0

Dislikes
Response

0

Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Kevin Conway - Western Power Pool - 4
Answer

Yes

Document Name
Comment
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0

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0

Response
Robert Follini - Avista - Avista Corporation - 3
Answer

Yes

Document Name
Comment
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0

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0

Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
Document Name
Comment

Yes

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0

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0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer
Document Name
Comment
Abstain
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0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE is concerned that multiple contingencies may not be used to assess the system in extreme temperature events. In Requirement R7, Table 1
only shows single contingencies and double circuit contingencies for assessing steady state and stability performances. Based on the contingencies
listed in Table 1, the reasoning for R7 is not clear. Are the responsible entities expected to select single contingencies and double circuit contingencies
and use those contingencies to assess the system? During extreme temperature events, multiple overlapping contingencies generally happens, and
they are expected. Registered entities should study the overlapping contingencies to identify system deficiencies and prepare the mitigation plans.

Additionally, the NERC Glossary Definition of Firm Transmission Service states: The highest quality (priority) service offered to customers under a filed
rate schedule that anticipates no planned interruption. Texas RE inquires as to why interruption of Firm Transmission Service is allowed under P0
conditions.
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Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion

Answer
Document Name
Comment
Dominion Energy supports EEI comments
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0

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Response

0

5. The DT updated Requirements R9 – R11 based on comments received. Do you agree with the updated proposed TPL-008-1 Reliability
Standard Requirements? If you do not agree, please provide your recommendation and, if appropriate, technical or procedural justification.
Devin Shines – LG&E/KU
Answer

Yes

Document Name
Comment
LG&E/KU agrees with the modifications in Requirements R9, R10, and R11. These modifications improve the clarity of the standard and, in the case of
Requirement R10, make a good change to permit possible actions designed to reduce the likelihood of the event to be considered as well.
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0

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0

Response

Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

No

Document Name
Comment
Many of the CHPD concerns from the previous draft redline still exist in this redline version. CHPD believes the updates made to R9 were very good,
with a couple concerns remaining. The first concern is to the statement ‘make its Corrective Action Plan available to’ in R9.1. CHPD suggests this be
changed to ‘make its Corrective Action Plan available on request’, to align with a similar request-based mechanism under R11. We’ve found the general
“make available” is murky language for compliance.
The second concern is the expectation in 9.1 and 9.2 for soliciting feedback and notifications to “regulatory authorities or governing bodies responsible
for retail electric service issues”. The intent here is not clear. Could the SDT provide some examples of what is intended here, both for Jurisdictional and
non-Jurisdictional entities? Our entity is a Public Utility District – who does the SDT envision we would provide this notification to – our publicly elected
commissioners?
It is noted that the R9 Measures now appear to include the solicitation and notification as part of the measures for compliance with R9 which is an
improvement from the previous draft version.
Lastly, in Order 896, FERC’s Commission determination in paragraph 157 reads:
“As stated above, we adopt and modify the NOPR proposal and direct NERC to require in the new or modified Reliability Standard the development of
corrective action plans that include mitigation for specified instances where performance requirements for extreme heat and cold events are not met—
i.e., when certain studies conducted under the Standard show that an extreme heat or cold event would result in cascading outages, uncontrolled
separation, or instability.”

FERC’s directive is when the outcome of studies would result in cascading outages, uncontrolled separation, or instability, a corrective action plan is
required. However, in TPL-008, the SDT has gone further. The current state of draft TPL-001-8 R9 states:
“Each responsible entity, as identified in Requirement R1, shall develop a Corrective Action Plan(s) when the analysis of a benchmark planning case, in
accordance with Requirement R8 Part 8.1, indicates its portion of the Bulk Electric System is unable to meet performance requirements for category P0
or P1 in Table 1. For each Corrective Action Plan, the responsible entity shall:”
The difference here is Order 896 is only requiring corrective action plans for cascading outages, uncontrolled separation, or instability. the SDT is
proposing to require corrective action plans for not meeting performance criteria, which also includes normal voltage limits or normal line ratings, even
though these exceedances may not result in cascading outages, uncontrolled separation, or instability. The request is for the SDT to align its R9
language with Order 896 paragraph 157 language. These other limits are needed to assess for cascading outages, uncontrolled separation, or
instability, but the requirement to develop a corrective action plan for such exceedances is beyond Order 896’s request for this proposed standard.
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Response
Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
The term, “Non-Consequential Load Loss,” is an oxymoron. It is also unrealistic to imagine that load shedding can be limited to a small, tolerable
amount. The uncertainties associated with extreme cold weather in particular are so severe that PCs and TPs should be required to serve all load with
a sizeable reserve margin.
The expression, “beyond their control,” should be replaced with an objective, auditable criterion.
CAPs for winter issues should be required to include early starting of generation units, to help accommodate the additional starting time that may be
required during extreme cold weather.

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0

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0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer
Document Name
Comment

No

The "applicable regulatory authorities or governing bodies responsible for retail electric service" in R9 needs better clarification - what does this look like
for jurisdictional vs non-jurisdictional - is this not applicable to non-jurisdictional? Ask of SDT to provide better guidance & examples.
Requirement R10 should explicitly clarify that a Corrective Action Plan is not required for P7 Contingencies, as stated in the previous draft 2, Table 2.1,
page 11.
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0

Response
Mark Flanary - Midwest Reliability Organization - 10
Answer

No

Document Name
Comment
In the current draft, it is not clear what the time frame is for providing the CAP or soliciting feedback from the regulatory authorities or governing bodies
in R9.1. In addition, there is no time frame when to notify the applicable regulatory authorities or governing bodies in R9.2. R9.4 indicates allowing
revision to the Corrective Action Plan but does not clarify when and what triggers the revision.
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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
(R9.1 and R9.2) We recommend that further clarification be given to how “applicable” regulatory authorities or governing bodies are determined. In
addition, we believe that soliciting feedback (R9.1) and notification (R9.2) should be replaced with “make available upon request.”
(R10) No issues.
(R11) We recommend that the timeframe be extended to 90 calendar days.
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0

Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

No

Document Name
Comment
Requirement #9.3 states:
“Be permitted to utilize Non-Consequential Load Loss as an interim solution, which normally is not permitted in Table 1, in situations that are beyond the
control of the Planning Coordinator or Transmission Planner that prevent the implementation of a Corrective Action Plan in the required timeframe,
provided that the responsible entity documents the situation causing the problem, alternatives evaluated, and takes actions to resolve the situation.”
The Extreme Temperature Assessment would have to be performed at least once every 5 years, assessing one year in the Long Term Planning
Horizon.
It is recognized that the details of the extreme heat/cold benchmark temperature events may change over time, and that the underlying assumptions
utilized in the Extreme Temperature Assessment for one of the years in the Long Term Planning Horizon may change over time. CAPs identified in one
Assessment may not be needed in a future Assessment. It may be difficult to pursue expensive CAPs understanding that assumptions may change.
With this in mind, we find it difficult from a compliance perspective to clearly identify what is meant by “in the required timeframe”. This language, while
allowing for flexibility, seems very ambiguous. The Technical Rationale does not elaborate on this point.
We recommend that the SDT clarify what is intended by “in the required timeframe.”
Comment on Requirement #11
Requirement #11 states:
“Each responsible entity, as identified in Requirement R1, shall provide its Extreme Temperature Assessment results within 60 calendar days of a
request to any functional entity that has a reliability related need and submits a written request for the information.”

This could be interpreted in different ways.
We would recommend the SDT consider modifying the wording (see TPL-001-5.1 Req #8 for reference) and timeframe to be more consistent with TPL001-5.1 Req #, 8 as follows:
“Each responsible entity, as identified in Requirement R1, shall provide its latest completed Extreme Temperature Assessment results within
90 calendar days of a request to any functional entity that has a reliability related need and submits a written request for the information.
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Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

No

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) on question 5
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Response
Sharon Darwin - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
Southern Company supports EEI’s comments.
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Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment
EEI has no concerns with Requirements R10 and R11, however, we do suggest changes to the subparts of Requirement R9 in order to more clearly
define R9.1-R9.3 as being specific to the utilization of ‘Non-Consequential Load Loss as an interim solution’ and to better align with TPL-001
Attachment 1 III (Instances for which Regulatory Review of Non-Consequential Load Loss under Footnote 12 is Required) with the TPL-008-1 Technical
Rationale.
Each responsible entity, as identified in Requirement R1, shall develop a Corrective Action Plan(s) when the analysis of a benchmark planning case, in
accordance with Requirement R8 Part 8.1, indicates its portion of the Bulk Electric System is unable to meet performance requirements for category P0
or P1 in Table 1. For each Corrective Action Plan, the responsible entity shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
9.1
{C}Be allowed to have revisions to the Corrective Action Plan in subsequent Extreme Temperature Assessments, provided that the planned Bulk
Electric System shall continue to meet the performance requirements of Table 1. (formally 9.4)
9.2
Be permitted to utilize Non-Consequential Load Loss as an interim solution, which normally is not permitted in Table 1, in situations that are
beyond the control of the Planning Coordinator or Transmission Planner that prevent the implementation of a Corrective Action Plan in the required
timeframe, provided that the responsible entity: (formally 9.3)

9.2.1

Documents the situation causing the problem, and make changes to mitigate the identified problem. (extracted from 9.3)

9.2.2
Documents alternative(s) considered and notifies the applicable regulatory authorities or governing bodies responsible for retail electric
service issues when Non-Consequential Load Loss is utilized as an element of a Corrective Action Plan for a Table 1 P1 Contingency. (Moved from old
9.2)
9.2.3
Make its Corrective Action Plan available to, and solicit feedback from, applicable regulatory authorities or governing bodies responsible for
retail electric service issues. (formally 9.1)
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Response
Joseph Knight - Joseph Knight On Behalf of: Jacalynn Bentz, Great River Energy, 3, 1, 5, 6; - Joseph Knight
Answer

No

Document Name
Comment
GRE supports the comments of the NSRF and GRE has additional comments
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Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

No

Document Name
Comment
AZPS supports the following comments submitted by EEI on behalf of its members:
EEI has no concerns with Requirements R10 and R11, however, we do suggest changes to the subparts of Requirement R9 in order to more clearly
define R9.1-R9.3 as being specific to the utilization of ‘Non-Consequential Load Loss as an interim solution’ and to better align with TPL-001
Attachment 1 III (Instances for which Regulatory Review of Non-Consequential Load Loss under Footnote 12 is Required) with the TPL-008-1 Technical
Rationale.
R9. Each responsible entity, as identified in Requirement R1, shall develop a Corrective Action Plan(s) when the analysis of a benchmark planning
case, in accordance with Requirement R8 Part 8.1, indicates its portion of the Bulk Electric System is unable to meet performance requirements for
category P0 or P1 in Table 1. For each Corrective Action Plan, the responsible entity shall: [Violation Risk Factor: High] [Time Horizon: Long-term
Planning]

9.1
Be allowed to have revisions to the Corrective Action Plan in subsequent Extreme Temperature Assessments, provided that the planned Bulk
Electric System shall continue to meet the performance requirements of Table 1. (formally 9.4)
9.2
Be permitted to utilize Non-Consequential Load Loss as an interim solution, which normally is not permitted in Table 1, in situations that are
beyond the control of the Planning Coordinator or Transmission Planner that prevent the implementation of a Corrective Action Plan in the required
timeframe, provided that the responsible entity: (formally 9.3)
9.2.1

Documents the situation causing the problem, and makes changes to mitigate the identified problem (extracted from 9.3)

9.2.2
Documents alternative(s) considered and notifies the applicable regulatory authorities or governing bodies responsible for retail electric
service issues when Non-Consequential Load Loss is utilized as an element of a Corrective Action Plan for a Table 1 P1 Contingency. (Moved from old
9.2)
9.2.3
Make its Corrective Action Plan available to, and solicit feedback from, applicable regulatory authorities or governing bodies responsible for
retail electric service issues. (formally 9.1)
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Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CEHE believes sensitivity cases are unnecessary and believes Requirement 10.2 should be removed since planning cases are already planned for
extreme events. Refer to CEHE’s comments in Q3. In the current draft, it is not clear what the timeframe is for providing the CAP in R9.1. In addition,
there is no timeframe when to notify the applicable regulatory authorities or governing bodies in R9.2. R9.4 indicates allowing revision to the Corrective
Action Plan but does not clarify when and what triggers the revision. R11 - CEHE recommends that the timeframe be extended to at least 90 calendar
days.
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Response
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Document Name
Comment
See EEI Comments

No

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Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

No

Document Name
Comment
Oncor strongly disagrees with the following statement in R9.1: “Make its Corrective Action Plan available to, and solicit feedback from, applicable
regulatory authorities or governing bodies responsible for retail electric service issues.” We propose that “applicable regulatory authorities or governing
bodies” be defined and limited. For example, a TP should only need to provide their PC with CAP information.
In addition, we disagree with the following phrase “and notify the applicable regulatory authorities or governing bodies responsible for retail electric
service issues” as it relates to Load Shed. The intended regulatory audience needs to be clearly defined.
Oncor disagrees with R10 as well. The requirement does not give TPs the ability to create CAPs for the listed contingencies.

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Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

No

Document Name
Comment
See EEI Comments
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Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
•
•
•
•
•

The purpose and required response actions related to the sharing of CAPs and solicitation of feedback is not clear.
Documentation of alternatives is an additional administrative burden and provides little benefit to reliability. It is also unclear if there is some
type of expectation these alternatives are reviewed or potentially challenged as invalid.
The role of the TO and/or GO in implementing or otherwise responding to CAPs that may require additions or modifications to their
systems/facilities is not captured in these requirements.
There appears to be a significant amount of outside review required but no clear actions the responsible entity is required to take, particularly if
there is a dispute. What is the purpose of the review and the expected response? This potentially produces an undue burden on the PC/TP
and adds subjectivity in requiring a review with no documented guidelines for conducting the review.
GTC recommends the restructuring of requirement 9 such that documentation of alternatives along with the sharing and soliciting feedback
back is only necessary when utilizing Non-Consequential Load Loss as an interim solution.

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Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

No

Document Name

2023-07_Unofficial_Comment_Form_Draft 3_100724 ITC (002).docx

Comment
See attachment with suggested changes.
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Response
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer

No

Document Name
Comment
SPP has multiple concerns around CAPs. The first concern is that the mechanism to issue a CAP for FERC Order 1000 is typically limited in SPP to
the Near-Term Transmission Planning Horizon. Secondly, if other SPP planning assessments evaluate extreme weather, SPP would like to consider
those CAPs for revision to the CAPs identified in the 5-year extreme temperature assessment. (potential verbiage could include Corrective Action Plan
in subsequent Extreme Temperature Assessments or other planning assessments that evaluate extreme weather conditions). This would also help if
other transmission projects came to fruition in between the 5-year assessments that could potentially mitigate the need for the CAP in the extreme
weather study.

Likes

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Response
Robert Blackney - Edison International - Southern California Edison Company - 1
Answer

No

Document Name
Comment
See comments submitted by Edison Electric Institute.
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Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

No

Document Name
Comment
Requirements R9 and R10 both regard obligations of the responsible entity based on inability to meet certain performance requirements. These
requirements should be combined into a single requirement (with sub-requirements) to make this aspect of the standard clearer to follow. With respect
to Requirement R9 Parts 9.1 and 9.2, it is unclear why Part 9.2 is necessary if the entire Corrective Action Plan is required to be made available to
applicable regulatory authorities or governing bodies responsible for retail electric service issues under Part 9.1. Perhaps Part 9.2 should instead be a
sub requirement under Part 9.1 that specifies certain information that must be included in the distributed Corrective Action Plan under Part 9.1;
otherwise, it may be confusing to the responsible entity how to implement Part 9.1 and Part 9.2 as separate items (including interpreting differences in
language such as “make available to” and “solicit feedback from” in Part 9.1 and “document” and “notify” in Part 9.2 directed to the same entities).
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Response
Michael Goggin - Grid Strategies LLC - 5
Answer
Document Name
Comment

No

a. Requirement R9 should be modified to specify that the expected impact of extreme heat and cold should be accounted for when designing and
measuring the impact of the solutions proposed in a Corrective Action Plan (CAP). Many potential solutions in a CAP can have greater or lesser impact
under extreme heat or cold conditions. For example, a CAP that relies on adding gas generation can be less effective under extreme heat due to output
reductions due to ambient temperature derates, and under extreme cold due to correlated gas generator outages. Gas generator outages due to
equipment failures and fuel supply interruptions have accounted for the majority of outages during recent cold snap events.{C}[1] As noted above in
response to question 4, FERC’s directive in paragraph 89 of Order 896 states that “it is necessary that responsible entities evaluate the risk of
correlated or concurrent outages and derates of all types of generation resources and transmission facilities as a result of extreme heat and cold
events.” On the other hand, CAPs that include demand response and energy efficiency programs related to building HVAC systems can offer
contributions that are larger than expected during extreme heat or cold because load associated with cooling or heating is higher during such events.
During extreme cold events, expanded transmission ties with neighboring grid operators can also exceed the benefits they offer under normal conditions
because transmission line thermal limits are higher during extreme cold and wind chill conditions. Transmission ties also tend to offer large benefits
during extreme heat and cold, as severe weather events tend to be at their most extreme in geographically confined areas, ensuring at least some
nearby grid operators are not experiencing shortfalls in generation.[2] The benefits of interregional transmission are even greater at higher renewable
penetrations.[3] The value of transmission ties during extreme heat and cold events should be accounted for when assessing baseline performance
during benchmark events as well as quantifying the value of expanding these ties as part of a CAP.
The higher transfer capacity of advanced conductors under extreme heat and cold conditions should also be accounted for, as carbon and composite
core conductors sag roughly half as much as comparable ACSR conductors. Finally, Grid-Enhancing Technologies like dynamic line ratings, topology
optimization, and power flow control devices offer significant benefits when the grid may be congested due to extreme temperatures. Dynamic line
ratings are particularly valuable for enabling operators to safely use transmission lines’ higher thermal limits during extreme cold and wind chill
conditions.
Accounting for how a CAP will fare under the extreme heat or cold conditions it is designed to solve is essential for ensuring reliability. Without
accounting for the reduced effectiveness of some CAP elements under extreme heat or cold, planners will be blind to potential reliability risks. In other
cases, failing to account for the effectiveness of specific CAP measures under extreme heat or cold will result in a suboptimal selection of solutions.
Extreme heat and cold must not only be accounted for in identifying reliability risks, but also designing solutions to those risks.
b. The draft of R9 also includes a potential loophole that a responsible entity could use to avoid implementing a CAP that is needed to address reliability
concerns.
First, allowing load curtailment for a P1 contingency under TPL-008 is a major departure from the requirements of TPL-001, which do not allow load
shedding for a P1 contingency.{C}[4] Allowing responsible entities plans’ to include load shed when they experience a single P1 contingency under
extreme heat or cold conditions is contrary to FERC’s intent in Order 896 that NERC enact a standard that will ensure reliable operations under extreme
heat and cold conditions.
More generally, a major concern with the draft standard is that there is no compliance mechanism to ensure CAPs are implemented. If implementing
some CAP solutions requires action by an entity other than the transmission planner or planning coordinator responsible entities, the draft standard
should be revised to include such a requirement on those entities. Other draft NERC standards include requirements to implement CAPs, and similar
language could be adopted for TPL-008. For example, requirement R9 of the PRC-028 draft requires a generator or transmission owner to “develop,
maintain, and implement a Corrective Action Plan to provide the required capability,”{C}[5] and requirement R6 of the PRC-030 draft requires “Each
applicable Generator Owner shall, for each of its CAPs developed pursuant to Requirement R5:
6.1. Implement the CAP;
6.2. Update the CAP if actions or timetables change; and
6.3. Notify each applicable Reliability Coordinator if CAP actions or timetables change and when the CAP is completed.”[6]{C}

{C}[1]{C} See, e.g., FERC and NERC, Winter Storm Elliott Report: Inquiry into Bulk-Power System Operations During December 2022 (October 2023),
https://www.ferc.gov/media/winter-storm-elliott-report-inquiry-bulk-power-system-operations-during-december-2022, at 17; FERC and NERC, The

February 2021 Cold Weather Outages in Texas and the South Central United States (November 2021), https://www.ferc.gov/media/february-2021-coldweather-outages-texas-and-south-central-united-states-ferc-nerc-and, at 16; FERC and NERC, 2019 FERC and NERC Staff Report: The South Central
United States Cold Weather Bulk Electric System Event of January 17, 2018 (July 2019), https://www.ferc.gov/legal/staff-reports/2019/07-18-19-fercnerc-report.pdf; PJM, Analysis of Operational Events and Market Impacts During the January 2014 Cold Weather Events (May 2014),
https://www.pjm.com/~/media/library/reports-notices/weather-related/20140509-analysis-of-operational-events-and-market-impacts-during-the-jan-2014cold-weather-events.ashx.
{C}[2]{C} https://acore.org/wp-content/uploads/2021/07/GS_Resilient-Transmission_proof.pdf
{C}[3]{C} https://www.nrel.gov/docs/fy22osti/78394.pdf
{C}[4]{C} https://www.nerc.com/pa/Stand/Reliability%20Standards/TPL-001-5.pdf, at 21
{C}[5]{C} https://www.nerc.com/pa/Stand/Project202104ModificationstoPRC0022DL/2021-04_AB_PRC-028-1_Clean_03182024.pdf
{C}[6]{C} https://www.nerc.com/pa/Stand/Project202302PerformanceofIBRsDL/2023-02%20PRC-030-1_032524.pdf
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Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
Comment
FirstEnergy has no comments toward these requirement drafts.
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0

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Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

Yes

Document Name
Comment
n/a
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0
0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
None.
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0

Response
Ronald Hoover - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
BPA supports leaving only P7 contingencies in R10
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0

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Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon agrees with the updated proposed TPL-008 Reliability Standard Requirements R9, R10, and R11.
Exelon would support the clarification suggested by the EEI for R9. .
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0

Kinte Whitehead - Exelon - 3
Answer

Yes

Document Name
Comment
Exelon agrees with the updated proposed TPL-008 Reliability Standard Requirements R9, R10, and R11.
Exelon would support the clarification suggested by the EEI for R9.
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Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Based on other projects that include developing and implementing CAPs, USV would feel more confident with the proposed modifications if there were
guidelines and more structured timelines set for the CAPs. Perhaps not in the standard itself, but guidance on timelines could be explained in the
technical rationale and include timelines for implementing CAPs and when entities can utilize backup action plans such as Non-Consequential Load
Loss.
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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
ERCOT understands Requirement R9 and Table 1 to allow the use of Non-Consequential Load Loss (NCLL) to address a performance deficiency in a
P1 event. ERCOT supports this approach, as the planning cases that TPL-008 addresses are based on extreme grid events that, coupled with a P1
scenario, are unlikely to reflect realistic future system conditions and therefore should not be treated the same way as planning events are treated under
TPL‑001-5.1. Consistent with this understanding, ERCOT recommends that Part 9.3 be revised as follows to more clearly align with the language in
Table 1:

“9.3. Be permitted to utilize Non-Consequential Load Loss as an interim solution, which normally is not permitted for P0 events in Table 1…”
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Thomas Foltz - AEP - 5
Answer

Yes

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Comment
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Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer

Yes

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Comment
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0

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0

Response
Robert Follini - Avista - Avista Corporation - 3
Answer

Yes

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Comment
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0

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0

Kevin Conway - Western Power Pool - 4
Answer

Yes

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Comment
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0

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Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

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Comment
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0

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0

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Michele Tondalo - United Illuminating Co. - 1
Answer

Yes

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Comment
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Ben Hammer - Western Area Power Administration - 1
Answer
Document Name
Comment

Yes

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Srikanth Chennupati - Entergy - 1,3,5,7 - SERC
Answer

Yes

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Comment
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0

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Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

Yes

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Comment
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0

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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

Yes

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Comment
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Helen Lainis - Independent Electricity System Operator - 2

Answer

Yes

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Comment
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Erin Wilson - NB Power Corporation - New Brunswick Power Transmission Corporation - 5
Answer

Yes

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Comment
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0

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Jeffrey Streifling - NB Power Corporation - 1
Answer

Yes

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Comment
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0

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Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

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Comment
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Robert Jones - Seattle City Light - 1,3,4,5,6
Answer

Yes

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Comment
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Jennie Wike - Jennie Wike On Behalf of: Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; John Merrell, Tacoma Public Utilities
(Tacoma, WA), 1, 4, 5, 6, 3; John Nierenberg, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; Ozan Ferrin, Tacoma Public Utilities (Tacoma,
WA), 1, 4, 5, 6, 3; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; - Jennie Wike, Group Name Tacoma Power
Answer

Yes

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Comment
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Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

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Comment
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0

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Joshua London - Eversource Energy - 1, Group Name Eversource

Answer

Yes

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Comment
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Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer

Yes

Document Name
Comment
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Bobbi Welch - Midcontinent ISO, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee (SRC) Project 2023-07 TPL-008-1 Draft #3
Answer

Yes

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Comment
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Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer

Yes

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Comment
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Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

Yes

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Comment
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Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

Yes

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Comment
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0

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Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

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Comment
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Greg Sorenson - Greg Sorenson On Behalf of: Tremayne Brown, ReliabilityFirst , 10; - ReliabilityFirst - 10 - RF
Answer

Yes

Document Name
Comment
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Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Document Name
Comment
Dominion Energy supports EEI comments
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Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer
Document Name
Comment
PNMR supports R10 and R11. PNMR supports EEI's proposed changes to R9.1 thru R9.4.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment

Texas RE continues to recommend including a timeframe for which the CAPs need to be developed and submitted for review once the benchmark
planning case study results indicate the System is unable to meet performance requirements.

Texas RE likewise continues to have concerns about the submission of CAPs solely to “applicable regulatory authorities…responsible for retail electric
service.” As an initial matter, it is unclear how this requirement will work in practice and how the ERO could maintain visibility into the CAP review
process. More broadly, since the Reliability Coordinator (RC) is the functional entity responsible for the Reliable Operation of the Bulk Electric System
within the NERC jurisdictional model, has the Wide Area view of the Bulk Electric System, and has the operating tools, processes and procedures,
including the authority to prevent or mitigate emergency operating situations, the CAP should at least be submitted to the RC in addition to applicable
regulatory authorities.

Consistent with this approach, Texas RE recommends the following revision:

9.1 Make their CAPs CAP available and solicit feedback from their Reliability Coordinator and applicable regulatory authorities or governing bodies
responsible for retail electric service issues within 60 days of developing the CAPs.
Additionally, Texas RE noticed that while Non-Consequential Load Loss is allowed for single and multiple circuit contingencies based on Table 1
performance criteria, the amount of Non-Consequential Load Loss allowed is not specified. This could lead to inconsistent application of load
interruptions to maintain system performance.
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Wayne Guttormson - SaskPower - 1
Answer
Document Name
Comment
R11 is purely administrative in nature and based on previous NERC/industry efforts to remove administrative details it should be removed. Technical
rationale provided for R11 seems lacking as to need and essentially could be used for any standard.
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0

6. The DT believes proposed modifications in TPL-008-1 provide entities with flexibility to meet the reliability objectives in a cost-effective
manner. Do you agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost-effective approaches,
please provide your recommendation and, if appropriate, technical or procedural justification.
Devin Shines – LG&E/KU
Answer

Yes

Document Name
Comment
The modifications in this draft improve entity flexibility while also providing much needed transparency and alignment with FERC directives. The FERC
directives in Order 896 will require a significant (and costly) effort to meet. Recognizing the DT must make a standard to meet these directives, the
modifications to TPL-008-1 make it effective while also allowing entities flexibility in meeting the reliability objectives.
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Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

No

Document Name
Comment
Sensitivity to generation, load and transfers are already studied as part of TPL-001-5.1 yearly for near and long-term scenarios (year 10/year 12). The
sensitivity additional studies proposed for R8.2 are unlikely to yield any new information and will be duplicative work for Transmission Planners.
The Extreme Temperature Assessment is already a very extreme sensitivity study itself that should already capture modified load, generation,
transmission, and transfers befitting this analysis per R3, so it is not needed nor appropriate to study sensitivities for sensitivity cases. Further sensitivity
cases to adjust such power flow variables would be a nice idea, but it does not appear cost effective to mandate developing and evaluating “sensitivity”
cases in addition to the already sensitive nature if the extreme weather assessment.
·
If sensitivity cases are deemed necessary, it would be more cost-effective to waive the obligation to study and analyze stability for those
sensitivities.
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0

Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer

No

Document Name
Comment
Being that this is a new assessment, entities will likely have to build additional models, coordinate with appropriate entities, perform the assessment,
and train staff, there will likely be a large cost associated with implementation of this standard.
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Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

No

Document Name
Comment
ITC believes it is not cost effective to build a sensitivity model and analyze the required events yet not require any Corrective Action Plans.
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Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
The attempt for flexibility is appreciated but this standard still falls short of something that is clear and allows the PC/TP to appropriately plan to meet
reliability goals. The inclusion of outside entity reviews of CAPs offers the reviewer flexibility as there are no bounds provided to them. The PC/TP,
however is potentially subjected to subjective reviews that have no framework with which the PC/TP can effectively respond.
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0

Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CEHE would be interested in more information on any economic analysis that was performed and believes the new Standard imposes a cost and time
burden to PCs/TPs without necessarily providing substantial benefits to the reliability of the BPS.
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Joseph Knight - Joseph Knight On Behalf of: Jacalynn Bentz, Great River Energy, 3, 1, 5, 6; - Joseph Knight
Answer

No

Document Name
Comment
GRE supports the comments of the NSRF and GRE has additional comments
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0

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0

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Jeffrey Streifling - NB Power Corporation - 1
Answer

No

Document Name
Comment
NERC already defines Reliability Coordinator as "The entity that ... has the Wide Area view of the Bulk Electric System...." Rather than asking individual
Planning Coordinators and Transmission Planners to coordinated in some ad-hoc, unspecified way, it might be more efficient to assign the responsibility
for identifying the weather zones and groups of planning entitites that should coordinate their studies to the Reliability Coordinator, who already has a
wide-area vew and is has operational experience with how the power system in their area behaves during temperature extremes.
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0

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0

Erin Wilson - NB Power Corporation - New Brunswick Power Transmission Corporation - 5
Answer

No

Document Name
Comment
NERC already defines Reliability Coordinator as "The entity that ... has the Wide Area view of the Bulk Electric System...." Rather than asking individual
Planning Coordinators and Transmission Planners to coordinated in some ad-hoc, unspecified way, it might be more efficient to assign the responsibility
for identifying the weather zones and groups of planning entitites that should coordinate their studies to the Reliability Coordinator, who already has a
wide-area vew and is has operational experience with how the power system in their area behaves during temperature extremes.
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0

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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
At this time, we are unable to fully agree that this standard provides the necessary flexibility to meet the reliability objectives in a cost-effective
manner. We would be interested in more information on any economic analysis that was performed.
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0

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0

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Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

No

Document Name
Comment
Duke Energy does not provide comments on cost effectiveness of the proposed modifications.
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0

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0

Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

No

Document Name
Comment
This consumes resources that could be put to better use in the basic TPL analysis.
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0

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0

Response
Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
The reliability objectives are not being met, ref. our comments above.
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0

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0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

No

Document Name
Comment
New Standard requiring extensive coordination with adjacent PCs/TPs within the defined “zones”. New Standards impose a cost and time burden to
PCs/TPs without necessarily providing substantial benefits to the reliability of the BPS.
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0

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0

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Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
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Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
Comment
While the DT is offering flexibility, we request the DT keep this standard from becoming overly prescriptive allowing members to obtain these in a cost
effective manner. Until we see the final result from the PC, FirstEnergy cannot fully determine flexibility to meet the reliability objectives in a costeffective manner.
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0

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Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

Yes

Document Name
Comment
The updates to TPL-008 in the Draft 3 redline provide more flexibility for entities to meet the objectives in the standard than previous draft versions. This
is best reflected by the removal of R2 language such that R2 no longer requires entities to select a benchmark event from the benchmark library if the
selected event meets the requirements described in R2.2.1 and R2.2.2.
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0

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Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
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0

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0

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Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment
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0

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0

Response
Michele Shafer - New York State Electric & Gas (NYSEG) - 6
Answer

Yes

Document Name
Comment
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0
0

Response
Kinte Whitehead - Exelon - 3
Answer

Yes

Document Name
Comment
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0

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0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Jennie Wike - Jennie Wike On Behalf of: Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; John Merrell, Tacoma Public Utilities
(Tacoma, WA), 1, 4, 5, 6, 3; John Nierenberg, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; Ozan Ferrin, Tacoma Public Utilities (Tacoma,
WA), 1, 4, 5, 6, 3; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1, 4, 5, 6, 3; - Jennie Wike, Group Name Tacoma Power
Answer

Yes

Document Name
Comment
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0

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0

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Sharon Darwin - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
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0

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0

Response
Robert Jones - Seattle City Light - 1,3,4,5,6
Answer

Yes

Document Name
Comment
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0

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0

Response
Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer

Yes

Document Name
Comment
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0

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0

Response
Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
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0
0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

Yes

Document Name
Comment
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0

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0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

Yes

Document Name
Comment
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0

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0

Response
Ronald Hoover - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
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0

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0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Duane Franke - Manitoba Hydro - 1,3,5,6 - MRO
Answer

Yes

Document Name
Comment
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0

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0

Response
Srikanth Chennupati - Entergy - 1,3,5,7 - SERC
Answer

Yes

Document Name
Comment
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0
0

Response
Michele Tondalo - United Illuminating Co. - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Kevin Conway - Western Power Pool - 4
Answer

Yes

Document Name
Comment
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0

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0

Response
Robert Follini - Avista - Avista Corporation - 3
Answer

Yes

Document Name
Comment
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0

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0

Response
Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
Document Name

Yes

Comment
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0

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0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
See EEI Comments
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0

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0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer
Document Name
Comment
Abstain
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0

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0

Response
Steven Rueckert - Western Electricity Coordinating Council - 10, Group Name WECC
Answer
Document Name
Comment
WECC leaves comments of the cost-effectiveness to those that must compy with the proposed standard.

Likes

0

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0

Response
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Document Name
Comment
See EEI Comments
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0

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0

Response
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer
Document Name
Comment
Ameren offers no comment on the cost effectiveness of the project.
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0

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0

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Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Document Name
Comment
MRO NSRF has no comment on the cost effectiveness of the draft language at this time.
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Response

7. Provide any additional comments for the drafting team to consider, including the provided technical rationale document, if desired.
Devin Shines – LG&E/KU
Answer
Document Name
Comment
This comment form did not include a question to provide feedback on the modifications to Table 1, but LG&E/KU supports all modifications.
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0

Response

Barbara Marion – Dominion Energy
Answer
Document Name
Comment
The issues deal primarily with the referenced methodology for referenced events as well as the arbitrary nature of dividing the country into study
regions based on the objectives of the proposed standard.
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0

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0

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Eric Sutlief - CMS Energy - Consumers Energy Company - 3,4,5 - RF
Answer
Document Name
Comment
Consumers Energy maintains its stance that the SDT must change “Bulk Power System (BPS)” to “Bulk Electric System (BES)” in section A.3. for
consistency with the proposed Extreme Temperature Assessment definition and TPL-001 purpose statement.

“Contingency BES Level” for a Category P0 event in Table 1 should be changed to “N/A” as there are no contingencies to be applied when the Event is
“None”. This would provide consistency with the Fault Type listing for the P0 Category as well.
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Thomas Foltz - AEP - 5
Answer
Document Name
Comment
AEP offers the following additional comments regarding potential overlapping or duplicative obligations.
R1’s “shall complete its responsibilities such that the … assessment is completed…” appears duplicative with R8’s “shall complete steady-state and
stability analysis… ”. AEP recommends removing the last sentence from R1 regarding completing the Extreme Temperature Assessment at least once
every five calendar years and appending it to R8.
Regarding R5, the TP and PC should already possess steady state voltage criteria to satisfy TPL-001 R5. As a result, AEP recommends removing R5
to avoid compliance risk associated with duplicative obligations. If the drafting team chooses to retain R5, the phrase “shall have criteria for acceptable
System steady state voltage limits and post-Contingency voltage deviations” might benefit from something more actionable than “shall have.” AEP
recommends the drafting team consider “shall devise” or “shall develop.”
R6’s identification of instability, uncontrolled separation, and cascading per criteria or methodology is already required in TPL-001 R6, which once again
appears duplicative and would unnecessarily increase compliance risk. AEP recommends it be removed.
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Response
Robert Follini - Avista - Avista Corporation - 3
Answer
Document Name
Comment
This includes all changes and/or clarifications requested by Avista
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0

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0

Kevin Conway - Western Power Pool - 4
Answer
Document Name
Comment
We would like to thank the STD for being responsive to the industry concerns and making this proposed standard more flexible for the various entities to
conform to.
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Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
Document Name
Comment
•
•

The clean-up of Table 1 to better align with TPL-001-5’s Table 1 is noted and appreciated.
The VRF for R5 was changed to “Medium” for this draft 3, however the VRF for R6 was not changed to “Medium”. It is requested the VRF for
R6 be set as “Medium” for consistency with TPL-008 R5.

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Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Document Name
Comment
No additional comments.
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0

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0

Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Document Name
Comment
MRO NSRF has no additional comments.
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Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer
Document Name
Comment
R6 VRF is 'High', but it should be set as ‘Medium’ to match TPL-008 R5, R7, and TPL 001-5 R6.
Corrective Action Plan requirement column should be added back to Table 1, as stated in the previous draft 2, Table 2.1, page 11.
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0

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0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
None.
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0

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0

Response
Michael Jones - National Grid USA - 1, Group Name National Grid

Answer
Document Name
Comment
National Grid supports EEI's comments and in-addition:
1. Please consider adding clarity regarding Stability Only Events, noting that in TPL-001-5.1 - Item j (Stability Only) was not included in Table 1 of TPL008-1. It is unclear whether the exclusion of Stability Only events was intentional or an unintentional omission. If this was unintentional, we suggest
adding the following:
Page 10 (Stability Only Section – NEW):
j.

Transient voltage response shall be within acceptable limits established by the Planning Coordinator and the Transmission Planner.

Note: If adding item j above was an unintentional omission, then we further suggest that the following edits are additionally required in Requirement
R5. See below:
Each responsible entity, as identified in Requirement R1, shall have criteria for acceptable System steady state voltage limits and post-Contingency
voltage deviations and the transient voltage response for its system for completing the Extreme Temperature Assessment. For transient voltage
response, the criteria shall at a minimum, specify a low voltage level and a maximum length of time that transient voltages may remain below that
level. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
2. Please consider adding a new footnote (Page 12 of Table 1) to better clarify the BES voltage levels for Events and align with Footnote 1 from TPL001-5.1 (See below)
For P0 and P1 events, the BES level of the event is the lowest System voltage level of the element(s) removed for the analyzed event. For P7 events,
the BES level of the event is the highest System voltage level of the element(s) removed for the analyzed event.
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Response
Ronald Hoover - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
BPA suggests that the Violation Risk Factor for R6 be changed from high to medium to be consistent with R5 as well as TPL-001 R5 and R6.
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0

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0

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Document Name
Comment
Please see EEI coments
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0

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0

Response
Kimberly Turco - Constellation - 6
Answer
Document Name
Comment
The zones identified in draft TPL-008-01, R2 cover large areas with widely varying temperature extremes. Selection of a single temperature event to
represent all generators within a zone is not realistic. The draft TPL-008 Tech Rationale acknowledges the limitation of using a single temperature over
wide areas. The NERC Standard EOP-12 extreme cold weather drafting teams struggled with the challenge of widely varying temperature conditions
across geographical areas and developed the Extreme Cold Weather Temperature (ECWT) as a "good enough" bounding temperature for cold weather
preparation planning. These ECWTs have been provided to PCs and TOPs as part of routine data requests from these entities. However, neither the
draft TPL-008 Standard or the Tech Rationale appear to include any consideration of the use of ECWT in planning studies, And the terms "extreme
cold" and "extreme heat' are not defined in the draft TPL-008 Standard. Suggest the Tech Rationale be revised to include some mention of the
generator cold weather planning Standard or the data which the PC / TOP may have requested from generators, as a way to "fine tune" the results of
the PC TPL-008 benchmark studies.

Kimberly Turco on behalf of Constellation Segments 5 and 6
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Alison MacKellar - Constellation - 5
Answer
Document Name
Comment

The zones identified in draft TPL-008-01, R2 cover large areas with widely varying temperature extremes. Selection of a single temperature event to
represent all generators within a zone is not realistic. The draft TPL-008 Tech Rationale acknowledges the limitation of using a single temperature over
wide areas. The NERC Standard EOP-12 extreme cold weather drafting teams struggled with the challenge of widely varying temperature conditions
across geographical areas and developed the Extreme Cold Weather Temperature (ECWT) as a "good enough" bounding temperature for cold weather
preparation planning. These ECWTs have been provided to PCs and TOPs as part of routine data requests from these entities. However, neither the
draft TPL-008 Standard or the Tech Rationale appear to include any consideration of the use of ECWT in planning studies, And the terms "extreme
cold" and "extreme heat' are not defined in the draft TPL-008 Standard. Suggest the Tech Rationale be revised to include some mention of the
generator cold weather planning Standard or the data which the PC / TOP may have requested from generators, as a way to "fine tune" the results of
the PC TPL-008 benchmark studies.
Alison Mackellar on behalf of Constellation Segments 5 and 6
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Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) on question 7
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Daniel Gacek - Exelon - 1
Answer
Document Name
Comment
Exelon supports the clarification suggested by the EEI for Table 1.
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0

Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer
Document Name
Comment
PNMR supports EEI's comments related to Table 1 events 1 & 6.
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Robert Jones - Seattle City Light - 1,3,4,5,6
Answer
Document Name
Comment
As stated above, since this standard requires entities come to a consensus on scenarios and and coordination methodology within each zone, there
should be some method of deispute resolution to ensure that process can be completed successfully.
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Sharon Darwin - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Answer
Document Name
Comment
Southern Company supports the additional comments provided by EEI.
Southern greatly appreciates the efforts of the SDT to address and incorporate industry feedback and is very encouraged by the changes made in
recent drafts.
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Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
EEI suggests the following changes to Table 1 – Steady State & Stability Performance Events as follows:
Formatting issue with P7 (Sensitivity Cases): The “Yes” statement is out of alignment with the other cells.
Page 10 (Steady State only Section)
Item h. from TPL-001-5.1 should be added to Table 1 of TPL-008-1 (see below):
h. Planning event P0 is applicable to Steady State only.
EEI asks for clarity regarding Stability Only Events, noting that in TPL-001-5.1 - Item j (Stability Only) was not included in Table 1 of TPL-0081. It is unclear whether the exclusion of Stability Only events was intentional or an unintentional omission. If this was unintentional, we
suggest adding the following:
EEI offers the following edits to Footnote 1 (Page 12), which we believe provides greater clarity to the footnote (proposed changes in
boldface below including first sentence removed):
For P1 events, the BES level of the event is determined by the lowest System voltage level of the elements(s) removed for the analyzed event.
For P7 events, the BES level of the event is determined by the highest System voltage level of the element(s) removed for the analyzed event.

EEI suggests that Footnote 6 (Page 12) be modified by deleting the first sentence because it is duplicative of the language already contained
in Requirement R9. See below (First Sentence Removed):
In benchmark planning cases, Non-Consequential Load Loss is not permitted for category P0 and requires notification of applicable regulatory
authorities or governing bodies responsible for retail electric service issues when utilized as an element of a Corrective Action Plan for P1
Contingencies. See Requirement R9 for the relevant requirements.

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Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Document Name
Comment

N/A
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Response
Michael Brytowski - Great River Energy - 3
Answer
Document Name
Comment
The current ordering of requirements R1, R2, & R3 creates confusion when reading the responsibilities of requirements 4-11. Consider reordering – R2,
R3 then R1. Coordinating Zones, develop benchmark planning then conducting the assessments. The Transmission Planner (TP) is not referenced in
R2 or R3.
R2 currently – Coordinating Zones
Each Planning Coordinator shall identify the zone(s) to which the Planning Coordinator belongs to under Attachment 1, and shall coordinate with all
Planning Coordinators within each of its identified zone(s), to select one common extreme heat benchmark temperature event and one common
extreme cold benchmark temperature event for each of its identified zone(s) when completing the Extreme Temperature Assessment.
R3 currently – a process for developing benchmark planning
Each Planning Coordinator shall coordinate with all Planning Coordinators within each of its zone(s) identified in Requirement R2, to implement a
process for developing benchmark planning cases for the Extreme Temperature Assessment that represent the benchmark temperature events
selected in Requirement R2 and sensitivity cases to demonstrate the impact of changes to the basic assumptions used in the benchmark planning
cases.
R1 currently – The assessments
Each Planning Coordinator shall identify, in conjunction with its Transmission Planner(s), each entity’s individual and joint responsibilities for completing
the Extreme Temperature Assessment, which shall include each of the responsibilities described in Requirements R2 through R11. Each responsible
entity shall complete its responsibilities such that the Extreme Temperature Assessment is completed at least once every five calendar years.
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Scott Brame, N/A, Brame Scott
0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Junji Yamaguchi, Hydro-Quebec (HQ), 1, 5; Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal
Mazza
Answer
Document Name

Comment
Our understanding of the Benchmark Process is that the Weather Zones were used to develop the lists (library) of Benchmark Events, and therefore
each Weather Zone has its library. Our interpretation of the current document would be that Québec shares the same library "Eastern Canada" as our
Canadian neighbors, without however having to choose the same events every 5 years because we are alone in our ETA Zone as per the table in
Attachment 1.
However, the Quebec zone vs. Eastern Canada zone should be clarified because the Technical Rationale does not distinguish between the two types of
zones (Weather Zones and ETA Zones), and rather gives the impression that it would normally be the same zone while the list under "Benchmark Event
Data" on the Project page give the impression that the Québec zone is included with the Eastern Canada zone. To be consistent with the table and the
map in Attachment 1, if we decided that we did not need to coordinate with our neighbors for the ETA, there is no reason for us to share the same
library, Québec should have a separate library.

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Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer
Document Name
Comment
AZPS supports the following comments submitted by EEI on behalf of its members:
EEI suggests the following changes to Table 1 – Steady State & Stability Performance Events as follows:
Formatting issue with P7 (Sensitivity Cases): The “Yes” statement is out of alignment with the other cells.
Page 10 (Steady State only Section)
Item h. from TPL-001-5.1 should be added to Table 1 of TPL-008-1 (see below):
h. Planning event P0 is applicable to Steady State only.
EEI asks for clarity regarding Stability Only Events, noting that in TPL-001-5.1 - Item j (Stability Only) was not included in Table 1 of TPL-008-1. It is
unclear whether the exclusion of Stability Only events was intentional or an unintentional omission. If this was unintentional, we suggest adding the
following:
EEI offers the following edits to Footnote 1 (Page 12), which we believe provides greater clarity to the footnote (proposed changes in boldface below):
For P1 events, the BES level of the event is determined by the lowest System voltage level of the elements(s) removed for the analyzed event. For P7
events, the BES level of the event is determined by the highest System voltage level of the element(s) removed for the analyzed event.
EEI suggests that Footnote 6 (Page 12) be modified by deleting the first sentence because it is duplicative of the language already contained in
Requirement R9. See below:

In benchmark planning cases, Non-Consequential Load Loss is not permitted for category P0 and requires notification of applicable regulatory
authorities or governing bodies responsible for retail electric service issues when utilized as an element of a Corrective Action Plan for P1
Contingencies. See Requirement R9 for the relevant requirements.
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Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer
Document Name
Comment
No additional comments.
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Bobbi Welch - Midcontinent ISO, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee (SRC) Project 2023-07 TPL-008-1 Draft #3
Answer
Document Name
Comment
For purposes of posterity, the SRC requests the standard drafting team provide a supporting explanation in the Technical Rationale justifying why P1
and P7 events are limited to >200 kV. Consider revising the Extreme Temperature Assessment definition to make it easier to read. The SRC proposes
the following language:
Extreme Temperature Assessment – Documented benchmark and sensitivity evaluation of future Bulk Electric System performance for extreme
heat and extreme cold benchmark temperature events.
The SRC recommends adding language for clarity of the number of cases needed. As currently drafted, TPL-008 R2 (winter / summer), R3 (benchmark
/ sensitivity), R4 & R5 (power flow), and R6 (dynamics) requires eight cases, however, this information is not straight forward and may lead to missed
cases.
The SRC requests clarification regarding R3.3 [Assumed seasonal and temperature dependent adjustments for Load, generation, Transmission, and
transfers in areas outside the zone, as needed.] In the event an area is lacking in resources to meet an extreme future case load, is the PC to assume
reliance on neighboring zones to import (and assume import capability) or can the CAP be to establish more resources (dependency or selfsufficiency)?
Please confirm that the PC selects which future year (within the long-term planning horizon) is studied, as long as it is greater than one year.

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Kinte Whitehead - Exelon - 3
Answer
Document Name
Comment
Exelon supports the clarification suggested by the EEI for Table 1.
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name NPCC RSC
Answer
Document Name
Comment
Attachment 1 – Extreme Temperature Assessment Zones in accordance with Requirement R2: We agree with Québec being its own Interconnection in
the map and in the table, however Québec is the only area that has its own zone in the table which does not correspond to a Weather Zone identified in
the Benchmark Process. Similarly, it is not in the list of benchmark temperature event data on the project page under “Benchmark Event Data”. For
example, ERCOT is identified as its own Interconnection and has its own list of benchmark temperature events. Another example is Florida in the
SERC region warrants a separate treatment and has its own benchmark temperature event data.

Our understanding of the Benchmark Process is that the Weather Zones were used to develop the lists (library) of Benchmark Events, and therefore
each Weather Zone has its library. Our interpretation of the current document would be that Québec shares the same library "Eastern Canada" as our
Canadian neighbors, without however having to choose the same events every 5 years because we are alone in our ETA Zone as per the table in
Attachment 1.

However, the Quebec zone vs. Eastern Canada zone should be clarified because the Technical Rationale does not distinguish between the two types of
zones (Weather Zones and ETA Zones), and rather gives the impression that it would normally be the same zone while the list under "Benchmark Event
Data" on the Project page give the impression that the Québec zone is included with the Eastern Canada zone. To be consistent with the table and the

map in Attachment 1, if we decided that we did not need to coordinate with our neighbors for the ETA, there is no reason for us to share the same
library, Québec should have a separate library.

Lastly, the Quebec zone does not appear in the TPL-008 Attachment 1 map, while it is in the table just above. We suggest adding the label “Québec” or
“Quebec Interconnection” in white font in the dark blue space represented by the province of Quebec.
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Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Document Name
Comment
See EEI Comments
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Romel Aquino - Edison International - Southern California Edison Company - 3
Answer
Document Name

Project 2023-07 TPL-008 Draft 3 Near Final Comments Rev. 0d 10_18_2024 (1).docx

Comment
Refer to Edison Electric comments.
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Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name

Comment
See EEI Comments
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Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments.
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Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer
Document Name
Comment
Additional comments regarding the listed requirements are as follows:
R5:
• The recently adopted NERC Glossary term, System Voltage Limits, should be referenced in this requirement instead of the outdated wording
“System steady state voltage limits”. “…shall have criteria for acceptable System Voltage Limits …”
• Since this requirement appears to refer to steady-state voltage, the post contingency voltage deviation portion of the existing requirement should
be removed. The resultant steady-state voltage level being outside of acceptable high and low limits is the point of concern. For example, if a low
voltage criterion is 0.92 p.u., then voltages below this limit would violate this particular criterion regardless of whether the beginning voltage was 0.95
p.u., 0.98 p.u., or any other voltage level.
R6:
• The inclusion of “within an Interconnection” is not appropriate as the PC or TP should not be required to assess outside of its applicable area.
Note the inclusion of more appropriate language referring to the PC’s or TP’s planning area (its portion of the Bulk Electric System) in this draft so it is
not clear why some requirements refer to an Interconnection while others, more correctly, refer to the area of actual responsibility for the PC or TP.

• The following bullet contains a wording addition to clarify the applicability of this requirement to System-wide impacts. This is also consistent with
wording in other Reliability Standards when referencing these types of impacts.
• “Each responsible entity, as identified in Requirement R1, shall define and document the criteria or methodology used in the Extreme
Temperature Assessment analysis to identify instability, uncontrolled separation, or Cascading of the Bulk Electric System.”
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Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer
Document Name

2023-07_Unofficial_Comment_Form_Draft 3_100724 ITC (002).docx

Comment
See attachment
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Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer
Document Name
Comment
N/A
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Greg Sorenson - Greg Sorenson On Behalf of: Tremayne Brown, ReliabilityFirst , 10; - ReliabilityFirst - 10 - RF
Answer
Document Name
Comment

The wording in R6 is similar to CIP-014 in that it could be more prescriptive in describing how an entity should study instability, uncontrolled separation,
or Cascading within an Interconnection. ReliabilityFirst and the other regions will assess the validity of judgments made by Registered Entities when
assessing this requirement.
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Robert Blackney - Edison International - Southern California Edison Company - 1
Answer
Document Name
Comment
See comments submitted by Edison Electric Institute.
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Michael Goggin - Grid Strategies LLC - 5
Answer
Document Name
Comment
We appreciate the Implementation Plan shortening of the compliance timeline for requirements R2-11 by one year. However, even with that change, the
draft Implementation Plan proposes that requirements R7-R11, which require the Extreme Temperature Assessment and any resulting Corrective
Action Plan and therefore constitute the substantive requirement of TPL-008, do not take effect until more than 5 years after the Standard is approved
by FERC. While this is an improvement relative to the 6-year delay in the prior draft, this timeframe is still excessive. This unnecessary delay is contrary
to FERC’s directive in Order 896 and the urgent importance of planning for extreme heat and cold events.
NERC’s 2023 State of Reliability Overview concluded that “extreme weather events continue to pose the greatest risk to reliability due to the increase in
frequency, footprint, duration, and severity.” FERC Order 896 was also clear that the increasing frequency and magnitude of extreme weather events
“have created an urgency to address the negative impact of extreme weather on the reliability of the Bulk-Power System” (at paragraphs 21-22).
Waiting until 2030 to address the largest threat to grid reliability does not make sense. Such a delay is also unnecessary, as entities responsible for
TPL-008 already conduct nearly all of the elements of TPL-008 today to comply with TPL-001. TPL-008 effectively requires running similar analyses as
TPL-001, but for extreme heat and cold scenarios. As a result, it should be straightforward for responsible entities to modify their existing planning
practices to incorporate the two additional scenarios.
This unnecessary delay is also at odds with FERC’s directive in Order 896. At paragraph 188, FERC directed “NERC to propose an implementation
timeline for the new or modified Reliability Standard, with implementation beginning no later than 12 months after the effective date of a Commission
order approving the proposed Reliability Standard.” Under the draft Implementation Plan, the only requirement of TPL-008 that comes close to falling

within the 12-month timeline FERC directed is compliance with R1, which begins “the first day of the first calendar quarter that is twelve (12) months
after the effective date of the applicable governmental authority’s order approving the standard.”
More importantly, R1 only requires that “Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall determine and identify each
entity’s individual and joint responsibilities for performing the studies needed to complete the Extreme Temperature Assessment,” and as such is a
minor procedural step towards implementing the actual Extreme Temperature Assessment and any resulting Corrective Action Plan in R7-R11. As
noted above, those meaningful requirements do not begin until more than 5 years after the standard is approved by FERC in the current draft. To
comply with FERC’s directive and the urgency of addressing extreme weather events, the drafting team should require compliance with R7-R11 to
begin at the effective date of the standard (around 12 months after FERC approval of the standard), and the interim steps in R2-R6 should also be
moved up from the current Implementation Plan’s proposed deadline of 24 months after the effective date of the standard.
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Summary Response to TPL-008-1 Draft 3
Comments Received

NERC Project 2023-07 Transmission Planning Performance Requirements
for Extreme Weather | November 2024
Comments Received Summary

There were 66 sets of responses, including comments from approximately 156 different people from
approximately 101 companies representing 10 of the Industry Segments. A summary of comments
submitted can be reviewed on the project page.
If you have an interest in joining the distribution list for this project, please reach out to Senior Standards
Developer, Jordan Mallory.
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 Manager of Standards Jamie Calderon (via email) or at (404) 960-0568.

Consideration of Comments

The NERC Project 2023-07 thanks all of industry for your time and comments. The drafting team (DT) feels
that many great points have been provided for the DT to consider during the drafting phase of this project.
High level themes received from industry are located below (bolded is the high-level theme followed by the
DT’s response).

Zones

Many commenters continued to express concerns that the temperature regions as proposed in the map
(and elsewhere) are in several cases far too large to provide meaningful analysis (e.g., MISO and SPP in
particular). Additionally, the benchmark temperature events identified for both MISO and SPP do not
represent what would be considered extreme temperature events due to their large geographically diverse
regions.
The zones shown in Attachment 1 lumps Ontario with the Maritimes (New Brunswick, Nova Scotia, and
parts of Northern Maine); however, practical experience has shown that there is no reliability benefit to
coordinating the extreme weather planning assessments for two reasons:
•

Experience has shown that Ontario and the Maritimes are sufficiently distant from each other as to
experience extreme temperature conditions at different times. An extreme temperature event in
Ontario would not occur at the same time as an extreme temperature event in the Maritimes.

•

The balancing areas of Ontario and the Maritimes are not adjacent and the capacity of the
transmission system to transfer power between Ontario and the Maritimes is small enough that

RELIABILITY | RESILIENCE | SECURITY

the power transferred between Ontario and the Maritimes would most likely be negligible during
an extreme temperature event.
For the NPCC region, it would make the most sense to divide the weather zones for extreme weather
planning assessments along the boundaries of the existing Reliability Coordinator areas, resulting in five
different weather zones:
•

ISO New York

•

ISO New England

•

Ontario

•

Quebec

•

The Maritimes, including New Brunswick, Nova Scotia, and Northern Maine

In addition to the foregoing, New Brunswick Power would like to support the comments of Helen Lainis,
Independent Electricity System Operator.
Drafting team response:
The DT agrees and NERC staff will work to get the zones modified to address the concerns received
regarding splitting certain zones into further sections. Below lists out the zones that have been split further.
This will be reflected in the map and Table 1 draft 4 posting of the TPL-008-1.
•

SPP (north and south)

•

MISO (north and south)

•

Ontario

•

Quebec

•

New Brunswick, Nova Scotia, Prince Edward Island, and Northern Maine

Overlapping Zones
A commenter expressed concern with overlapping zones within neighboring entities and should be allowed
to meet the requirements of extreme weather conditions. Although we agree that the focus of the study is
within the boundary, PCs should have the flexibility to consider maybe a little bit past the confines of the
identified zone as identified in Attachment 1.
Drafting team response:
The TPL-008-1 is the bare minimum of what is required. If a PC determines that it needs to coordinate with
PCs in other zones, it is more than welcome to coordinate.

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Weather Data
One commenter expressed concern with picking weather data that is comparable between New Mexico
and Arizona. We believe differences in weather patterns would impact New Mexico study if building that
study to Arizona's summer temperatures.
Drafting team response:
The ERO benchmark data provided is aggregated for that zone and not specific areas. Therefore, you would
not be subject to the summer temperatures of Arizona. Data used to make this inclusion uses zip code by
zip code data.

Benchmark Events

Some commenters expressed that the benchmark events should be included as an attachment to the TPL008-1 Standard.
Drafting team response:
The DT disagrees with this route for multiple reasons listed below.
1. There will be around 59 plus tables needed to be created, which will make for a 100-plus page
standard.
2. Feedback received is that entities appreciate the Excel option to be able to filter and sort, where
necessary, when sorting through all the data provided in the benchmark temperature.
3. NERC will need to put together a DT and open the TPL-008-1 standard to update the attachment
with ERO benchmark event data every five years and complete this in a timely manner for industry.
With Requirement R2 being updated, the DT does not see the need for all benchmark events to be
added as an attachment to TPL-008-1.

How to use Benchmark Events

A commenter requested that the drafting team clarify how the event temperature information (available
on NERC’s website) is intended to be used, and more specifically, whether it is to be applied across the
entire zone.
Drafting team response:
The data provided has been calculated via the entire zone identified in table 1. This is no different from
other studies that have been completed.

Requirement Order Confusion

Requirement R2 and R3 following R1 creates confusion when reading the responsibilities of requirements
4-11. Consider reordering – R2, R3 then R1. Coordinating Zones, develop benchmark planning then
conducting the assessments. The Transmission Planner (TP) is not referenced in R2 or R3.
Drafting team response:

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The drafting team determined R1, R2, and R3 are in the appropriate order. R1 requires the PCs and its TP(s)
to discuss and identify responsibilities. Although R2 and R3 are applicable to the PC only, TPs may want to
inform their PC they want to be included in R2 and R3 activities during the initial R1 discussions. For
instance, TPs may want to provide feedback to their PCs with respect to the selection of the benchmark
temperature events and/or the implementation of the process for developing benchmark planning cases.

Requirement R1
Document

A commenter requested the drafting team (DT) add document to Requirement R1.
Drafting team response:
The DT followed TPL-007-4 and how it was drafted and did not add “document” to Requirement R1. The DT
recognizes there has been a lot of back and forth as to whether document is needed in various standards
and does not feel it is necessary to be used in this instance.

Requirement R2
Planning Coordinator Development Benchmark Events

Some commenters expressed that Requirement R2 be made clear that Planning Coordinators are allowed
to develop their own benchmark events should the benchmark events provided by the ERO are not
sufficient for its zone.
Drafting team response:
FERC Order 896 recognizes that historical events may span across regions and therefore, the ERO is in the
best position to develop benchmark events. The DT updated the TPL-008-1 Standard to ensure it is clear
that TPL-008-1 allows Planning Coordinators, in coordination with other Planning Coordinators, to
develop benchmark events, should the events provided by the ERO not be adequate for Planning
Coordinators to consider. As a reminder, one common extreme heat benchmark temperature event and
one common extreme cold benchmark temperature event are to be identified and studied among the PCs
within the zone identified in Attachment 1 of the TPL-008-1 Standard.

Requirement for NERC to Coordinate with PCs

Some commenters expressed that a requirement should be added to the TPL-008-1 standard requiring
NERC to coordinate with Planning Coordinators when developing benchmark events.
Drafting team response:
A NERC Process 1 has been developed and posted to the NERC Project 2023-07 page laying out the process
for the 5-year iteration of benchmark events being developed. Please see this document for next steps on
future benchmark event development.
1

Link to NERC Process document: NERC Standards Development Process Document

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Year Events

A commenter suggested that if the goal is for the PCs to study a one in 40-year event for temperature that
each PC perform a study for their footprint and share results to the adjacent PCs, similar to the way existing
NERC standards are coordinated. For instance, there are other standards that utilize language for the
applicable entity to study its PC footprint and coordinate with 1st tier entities. SPP believes that language
similar to this can accomplish the intended goal without creating a burden if the boundaries change in the
Map.
Drafting team response:
The goal is not for the PC to study a one in 40-year event. TPL-008-1 is to study an extreme cold or extreme
heat event considered no less than a 40-year period of temperature data.

Years Used for Benchmark Events

40 years of temperature data is an immense amount of data. The data collected 40 years ago compared to
today’s temperatures may not be accurate and could construe the data from the last 20-25 years. We
believe that there have been enough recent extreme weather events in the last 25 years to accurately
consider extreme heat and extreme cold benchmark temperatures. We recommend that the drafting team
consider utilizing a timeline closer to 20 years and not 40 years.
Another commenter proposed 50 years should be used.
Drafting team response:
The requirement to consider no less than 40 years of temperature data was established based on the
observation that many of the worst events identified in various regions of North America occurred in the
1980s and 1990s. For example, preliminary data indicated that the five worst extreme cold temperature
events in the PJM region over the last 43 years occurred between 1983 and 1994. Similar results were seen
in other regions for both extreme heat and extreme cold temperature events. Thus, the SDT determined
that a minimum of 40 years of temperature data should be used to ensure more extreme events weren’t
excluded by using a shorter duration of temperature data.
Regarding 50-year proposal. There is nothing that precludes an entity from pulling 50-years of data, should
they find this more beneficial. A standard provides the bare minimum of what is required and anything
above and beyond is not precluded from an entity from considering.

Disagreements during coordination

There should be some method to help ensure coordination on scenario selection and case data submittal
among all PCs in a zone. How will disagreements among PC's be resolved? Voting? Regions can probably
resolve this on their own most of the time, but there may be disputes that need to be resolved somehow.
Drafting Team Response:

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The DT understands that this may happen and enough time during implementation has been provided for
additional meetings to work through disagreements. In addition, if majority of the PCs within the zone
agree, then the team would recommend going the route of majority and let the entity who is in
disagreement work through their justification when it comes time for them to be audited. Lastly, entities
are welcome to reach out to their Regional Entities if a disagreement comes up to guidance, if needed.

Requirement R2 Subparts – Too Prescriptive

One commenter believes the language in sections 2.1 and 2.2 are too prescriptive. We believe the Planning
Coordinator should work with stakeholders to determine the data set that will be used to derive extreme
heat and cold weather temperatures. Does the planning coordinator have the ability to carve the zones?
Drafting team response:
Benchmark event data provided by the ERO are there for entities to review and determine what data works
for their zone. R2 also allows entities to develop their own benchmark temperature event, should the data
provided not be allowed. In addition, criteria is needed per FERC Order 896 and Parts 2.1 and 2.2 to
complete this. Order 896: “We also direct NERC to include in the Reliability Standard the framework and
criteria that responsible entities shall use to develop from the relevant benchmark event planning cases to
represent potential weather-related contingencies”.

Extreme Event selection

The new requirement proposed in R2 2.1 in the updated draft that the event selected represent “one of
the 20 most extreme temperature conditions” may result in entities selecting events that are not
representative of the most severe generation shortfalls they are likely to experience. First, entities should
be required to select from a smaller number of most severe events, like the three most severe events.
Second, the ranking of events should not be based on most extreme temperature, but rather most severe
generation shortage, accounting for both higher demand and higher generator outage rates during the
event. This will accurately reflect that temperature alone does not determine the severity of an event, as
wind speed, insulation, and other factors affect how extreme cold and heat affect both generator outages
and the need for building heating or cooling.
Drafting team response:
The DT understands the concern. However, when considering extreme events over a 3-day rolling average
over 40-years does not provide a ton of data to work from. While yes, extreme events have become more
common in recent years, it is important for an entity to be able to evaluate events that happened over 40years as some of the events may not be extreme compared to other events. It is important to collect 20
extreme events to review and consider which event to study for further studies. Pulling data for 10 most
extreme events may not provide the full picture of events to review and select from.

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Requirement R3/R4

Transmission Planners Missing

The prior draft of TPL-008 contained language in R3 that required “Planning Coordinator(s), Transmission
Planner(s), and other designated study entities” to collectively implement the requirement. The SRC
requests language along these lines be reinstated such that all parties that play a role in implementing the
process for developing benchmark planning cases must comply.
Drafting team response:
Coordination is at the PC level and not the TP level. Therefore, the team removed this from the last draft,
and it does not need to be added back in.

Benchmark Event Framework

Some commenters requested the DT to clarify “other designated entities.”
Drafting team response:
The DT removed “other designated entities” from the TPL-008-1 Standard.

Number of Studies Required

Some commenters expressed concern regarding the number of studies which must be performed,
particularly when a Planning Coordinator (PC) selects a benchmark temperature event that is different
from that of its adjacent PC(s). In that situation, each benchmark temperature event may necessitate a
significant coordination effort. It was recommended that a governing body identify the scenarios. Extreme
temperature events will typically extend beyond the footprint of a single Planning Coordinator. To avoid
putting the PCs in a position where they are required to agree on a scenario, a year and the sensitivity to
be studied, NERC or other (e.g. ERAG) should identify the extreme heat and extreme cold temperature
events to be studied. This is necessary for consistent modeling results across adjacent planning entities.
Also, as a benchmark temperature event may extend across several planning areas, the governing body
must take this into consideration when determining which extreme heat and extreme cold temperature
events are to be studied so that no planning entity is assigned more than one of each.
Drafting team response:
The DT updated the TPL-008-1 Standard to identify that one common extreme heat and one common
extreme cold benchmark planning case must be developed, as well as at least one common extreme heat
and one common extreme cold sensitivity case. This does not preclude entities from developing more cases,
but requires a minimum of one each. Per the FERC Order 896, it is important that entities are studying
common historical events in preparation for future events. The ERO will provide entities with one common
extreme heat benchmark temperature event and one common extreme cold benchmark temperature
event for PCs to study within their zones. In addition, the TPL-008-1 Standard has been updated to allow
PCs to coordinate with other PCs to develop their own benchmark event should the events provided by the
ERO not be adequate for Planning Coordinators to consider.

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Extreme Weather is a Sensitivity

Some commenters expressed that Extreme Temperature Events are already a “sensitivity” to normal longterm planning cases and are built with Gen/Load/Transfer based on the extreme weather conditions of an
entity’s territory. Additionally, mandatory “sensitivity cases” seem redundant in nature. In addition,
another commenter asked if sensitivity cases could be baked-in with the benchmark temperature event.
Drafting team response:
TPL-008-1 is different than TPL-001-5.1. The TPL-008-1 Standard focuses on extreme heat and extreme cold
temperature events. Entities are to select an extreme heat and cold benchmark event, develop planning
cases, and then develop sensitivity cases from that, which may indicate a different approach on how to
handle certain scenarios.
Additionally, FERC Order 896 P124 states that “we adopt the NOPR proposal and direct NERC to require the
use of sensitivity cases to demonstrate the impact of changes to the assumptions used in the benchmark
planning case. Sensitivity analyses help a transmission planner to determine if the results of the base case
are sensitive to changes in the inputs. The use of sensitivity analyses is particularly necessary when studying
extreme heat and cold events because some of the assumptions made when developing a base case may
change if temperatures change – for example, during extreme cold events, load may increase as
temperatures decrease, while a decrease in temperature may result in a decrease in generation. We agree
with AEP, and we direct NERC to define during the Reliability Standard development process a baseline set
of sensitivities for the new or modified Reliability Standard. While we do not require the inclusion of any
specific sensitivity in this final rule, NERC should consider including conditions that vary with temperature
such as load, generation, and system transfers.” P126 continues to explain that “[w]e disagree with NYISO
and LCRA that extreme heat and cold weather impacts are already studied as sensitivities under Reliability
Standard TPL-001-5.1. Although TPL-001-5.1 mandates sensitivity analysis by varying one or more
conditions specified in the standard such as load, generation, and transfers, this analysis alone cannot
capture the complexities of extreme heat and cold weather conditions. Sensitivity analyses consider the
impact on a base case of the variability of discrete variables. Extreme heat and cold weather impacts, on
the other hand, may include numerous concurrent outages and derates which cannot be studied as part of
a single-variable sensitivity analysis.”

TPL-008-1 Cases Used for TPL-001-5.1

One commenter asked whether language can be added to ensure that entities can take credit for studies
that are run as part of the Sensitivity analysis, rather than running those studies again as part of the
assessment to be conducted under TPL-001. For example, the Extreme Temperature Assessment could take
the place of the sensitivity analysis required within the TPL-001 assessment for both the steady state and
stability analyses. Moreover, if the Extreme Temperature Assessment is essentially a type of sensitivity
analysis already, the commenter advised removing R4.2 because this would create a sensitivity case based
on a sensitivity case.
Drafting team response:

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A Planning Assessment must be completed annually in accordance with TPL-001-5.1, while an Extreme
Temperature Assessment must be completed at least once every five calendar years in accordance with
the TPL-008-1 Standard. Time will be required to coordinate and develop the common cases and
therefore, may not meet what is required in TPL-001. TPL-008-1 does not speak to TPL-001; however,
both standards have different expectations. The DT does not encourage this, but if an entity decided to go
this route, it would be up to that entity to explain and demonstrate compliance with the TPL-008-1
Standard.

Concurrent/Correlated Outage Language

Some commenters expressed that in Order 896 paragraph 88, FERC directs “NERC to require under the
new or revised Reliability Standard the study of concurrent/correlated generator and transmission
outages due to extreme heat and cold events in benchmark events,” explaining in paragraph 89 that “it is
necessary that responsible entities evaluate the risk of correlated or concurrent outages and derates of all
types of generation resources and transmission facilities as a result of extreme heat and cold events.”
Commenters suggested modifying “Benchmark planning cases that include seasonal and temperature
dependent adjustments for Load, generation, Transmission, and transfers” to include
“concurrent/correlated generator and transmission outages.”
Drafting team response:
Concurrent/correlated outages are addressed through the standard. The DT did not use language verbatim,
but the standard is laid out on adjustment of temperature data that is provided by the event selection.
Aligning with the directives set forth in FERC Order 896, which emphasizes the importance of incorporating
derated generation, transmission capacity, and the availability of generation and transmission in the
development of benchmark planning cases, it becomes imperative for responsible entities to consider
potential concurrent or correlated generation and transmission outages and/or derates within relevant
benchmark planning cases. This ensures that the benchmark planning case accurately reflects System
conditions under extreme temperatures, with generation and transmission derates and/or outages already
factored.

MOD-032 Data

Some commenters asked if the DT feels it would be necessary to add any additional data to the table in
MOD-032 to complete this work. In addition, some sought clarification on how MOD-032 will allow for the
collection of additional information related to extreme heat and cold events.
Drafting team response:
MOD-032 ensures an adequate means of data collection for transmission planning and requires applicable
registered entities to provide steady-state, dynamic, and short circuit modeling data to their Transmission
Planner(s) and Planning Coordinator(s). As outlined in R1 and Attachment 1 of MOD-032, MOD-032 allows
various data collection such as in-service status and capability associated with demand, generation, and
transmission associated with various case types, scenarios, system operating states, or conditions for the
long-term planning horizon. MOD-032 also requires applicable registered entities to provide “other

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9

information requested by the Planning Coordinator or Transmission Planner necessary for modeling
purposes” for each of the three types of data required. Because the DT determined the responsible entities
that will be developing benchmark planning cases are limited to Planning Coordinators and Transmission
Planners, they will be able to request and receive needed data pursuant to MOD-032. Thus, the DT believes
that there is no need to update MOD-032 because it allows Planning Coordinators and Transmission
Planners to request any specific data needed for developing benchmark planning cases and sensitivity cases
required in R4 of TPL-008-1.

Contingencies

In FERC Order 896, paragraph 39, there is a Commission Determination as follows:
“We also direct NERC to include in the Reliability Standard the framework and criteria that responsible
entities shall use to develop from the relevant benchmark event planning cases to represent potential
weather-related contingencies (e.g., concurrent/correlated generation and transmission outages, derates)
and expected future conditions of the system such as changes in load, transfers, and generation resource
mix, and impacts on generators sensitive to extreme heat or cold, due to the weather conditions indicated
in the benchmark events. Developing such a framework would provide a common design basis for
responsible entities to follow when creating benchmark planning cases. This would not only help establish
a clear set of expectations for responsible entities to follow when developing benchmark planning events,
but also facilitate auditing and enforcement of the Standard.”
In review of Order 896, we find the term “contingencies” is used two different ways. Paragraph 39 describes
things that are in the base or N-0 state – for example, a cold weather event occurs, and certain wind
generators can no longer operate – this as a base contingency. Similarly, in paragraph 88, there is an
additional Commission Determination as follows, in further support of these baseline “contingency”
outages:
“Pursuant to section 215(d)(5) of the FPA, we adopt the NOPR proposal and direct NERC to require under
the new or revised Reliability Standard the study of concurrent/correlated generator and transmission
outages due to extreme heat and cold events in benchmark events as described in more detail below.”
Then later, in Paragraph 92 (still under the Commission Determination), FERC further clarifies:
“Regarding the comments of NYISO and EPRI on the difference between extreme events and contingencies
covered under Reliability Standard TPL-001-5.1, we clarify that all contingencies included in benchmark
planning cases under the new or modified Reliability Standard will represent initial conditions for extreme
weather event planning and analysis. These contingencies (i.e., correlated/concurrent, temperature
sensitive outages, and derates) shall be identified based on similar contingencies that occurred in recent
extreme weather events or expected to occur in future forecasted events.”
From these, it is clear that Order 896 is expecting “contingencies” of weather-based equipment outages to
be part of the base or N-0 system state. The more traditional “contingencies” are then addressed on top of
this condition, as presented in Order 896, Section G, starting at Paragraph 95.
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10

The specific request from this comment is for the SDT to clarify how it expects such base “contingencies”
to be included in the model. There does not appear to be language currently in the standard in support of
this, and it is clear from Order 896 that it is expected both the base model outage “contingencies” and then
subsequent contingency events to test system performance.
Drafting team response:
The SDT drafted Requirement R4 to require the responsible entity to use data consistent with Reliability
Standard MOD-032, supplemented by other sources as needed, for developing benchmark planning cases
that represent System conditions based on selected benchmark temperature events. This aligns with
directives in FERC Order No. 896, paragraph 30, emphasizing the requirement of developing both
benchmark planning cases and sensitivity study cases. Requirement R4 is consistent with Reliability
Standard TPL-001-5.1 in cross-referencing Reliability Standard MOD-032, which establishes consistent
modeling data requirements and reporting procedures for the development of planning horizon cases
necessary to support analysis of the reliability of the interconnected System. It is also consistent with
Reliability Standard TPL-001-5.1 in acknowledging that data from other sources may be required to
supplement the data collected through Reliability Standard MOD-032 procedures.
The benchmark planning cases and sensitivity cases developed in Requirements R4.1 and R4.2, respectively,
shall include forecasted seasonal and temperature dependent adjustments for Load, generation,
Transmission, and transfers within the zone in accordance with Requirement R3.2, and assumed seasonal
and temperature dependent adjustments for Load, generation, Transmission, and transfers in areas outside
the zone, as needed, in accordance with Requirement R3.3. The seasonal and temperature dependent
adjustments included during the development of the benchmark planning cases and sensitivity cases
establish category P0 as the normal System condition in Table 1. Subsequently, the Contingencies for each
category in Table 1 that are expected to produce more severe System impacts on the responsible entity’s
portion of the Bulk Electric System shall be identified in accordance with Requirement R7 and evaluated in
both steady state and transient stability analyses in accordance with Requirement R8 for the benchmark
planning cases and sensitivity cases developed in Requirements R4.1 and R4.2, respectively.

Requirement R5

Use of “System Voltage Limits”

Some comments suggested using the recently adopted NERC Glossary term “System Voltage Limits.”
Drafting team response:
The DT determined “System Voltage Limits” focuses on operations and planning information and differs
from what is used in the standard. The DT concluded to maintain the proposed language consistent with
Reliability Standard TPL-001-5.1.

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11

Requirement R6

Violation Risk Factor

The risk factor should be Medium to match TPL 001-5.1. Concern that level of coordination needed to
affect the standard will be significant, particularly for “smaller” entities.
Drafting team response:
The DT determined that based on the planning for events such as instability, uncontrolled separation, or
Cascading events would consist of a high VRF and therefore, kept the VRF as high. This is consistent with
the definition of a high VRF in the justification document provided on the NERC website.

Requirement R8

Performance of Steady State and/or Stability Analysis

The standard does not clearly and specifically state whether steady-state and/or stability analysis is to be
performed for the identified events as TPL-001 does, for instance. The DT should consider modifying R7
to allow the responsible entity to develop a methodology or rationale in the performance of a benchmark
event to appropriately assess it for that entity’s planning area, otherwise, additional clarity in the analysis
expectations is needed. Different weather events would require a different consideration of applicable
contingencies and analysis approaches.
Drafting team response:
Requirement 4 has been updated to state one common extreme heat and one common extreme cold. In
addition, R8 has been updated to clarify that steady state and transient stability analyses are to be
performed.

Additional Sensitivity Cases

Additional sensitivity studies required in R8.2 would add a significant administrative burden without more
clarification to how it benefits the long-term planning horizon.
Drafting team response:
Table 1 has been updated to require P0, P1, and P7 Contingencies. R4 has also been updated to clarify
that it is one common extreme heat and one common extreme cold benchmark planning case, as well as
at least one common extreme heat and one common extreme cold sensitivity case. In addition, this is a
directive from the FERC Order 896 P124 which states “we adopt the NOPR proposal and direct NERC to
require the use of sensitivity cases to demonstrate the impact of changes to the assumptions used in the
benchmark planning case. Sensitivity analyses help a transmission planner to determine if the results of
the base case are sensitive to changes in the inputs. The use of sensitivity analyses is particularly
necessary when studying extreme heat and cold events because some of the assumptions made when
developing a base case may change if temperatures change – for example, during extreme cold events,
load may increase as temperatures decrease, while a decrease in temperature may result in a decrease in
generation. We agree with AEP, and we direct NERC to define during the Reliability Standard

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12

development process a baseline set of sensitivities for the new or modified Reliability Standard. While we
do not require the inclusion of any specific sensitivity in this final rule, NERC should consider including
conditions that vary with temperature such as load, generation, and system transfers.”

Requirement R9

Regulatory Burden

Some commenters raised concerns about the requirement to submit CAPs to regulatory authorities,
suggesting it could delay approval, lacks justification, need clearer definitions, and should be limited or
removed.
Drafting team response
The DT reviewed the comments and determined that the requirement is necessary to address the directives
of Order 896, specifically the directives mentioned in the paragraphs 152 (i.e., “we direct NERC to develop
certain processes to facilitate interaction and coordination with applicable regulatory authorities or
governing bodies responsible for retail electric service as appropriate in implementing a corrective action
plan”) and 165 (i.e., “we direct NERC to require in the new or modified Reliability Standard that responsible
entities share their corrective action plans with, and solicit feedback from, applicable regulatory authorities
or governing bodies responsible for retail electric service issues”).

Clarity on Sensitivity Analysis

Various commenters questioned the necessity of a Corrective Action Plan for issues identified in sensitivity
analysis, seeking clarity on how sensitivity analysis is handled.
Drafting team response
The DT updated Requirement R9 to clarify that Corrective Action Plans are not required specifically for
addressing performance requirements related to sensitivity cases. The responsible entity must develop
Corrective Action Plan(s) when the analysis of a benchmark planning case indicates its portion of the Bulk
Electric System is unable to meet performance requirements for Table 1 P0 or P1 Contingencies.

CAP Request

A commenter requested the DT to ‘make their CAP available’ in R9.1 to ‘make available on request.’
Drafting team response
FERC Order 896 P153 states: “We adopt our rationale set forth in the NOPR and conclude that the directive
to require the development of corrective action plans is needed for Reliable Operation of the Bulk-Power
System. Under the currently effective Reliability Standard TPL-001-5.1, planning coordinators and
transmission planners are required to evaluate possible actions to reduce the likelihood or mitigate the
consequences of extreme weather events, but are not obligated to develop corrective action plans, even if
such events are found to cause cascading outages. Experience over the past decade has demonstrated that
the potential severity of extreme heat and cold weather events exacerbates the likelihood to cause system
instability, uncontrolled separation, or cascading failures as a result of a sudden disturbance or
unanticipated failure of system elements. Thus, we conclude that entities should proactively address

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather | Draft 3
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13

known system vulnerabilities by developing corrective action plans that include mitigation for specified
instances where performance requirements for extreme heat and cold events are not met.” Therefore, it
is the responsibility of the PC or TP developing the CAPs to provide this information to the respective
governing bodies and solicit feedback per the FERC Order.

CAP Process

There are already existing processes for interactions with applicable regulatory authorities and governing
bodies regarding CAP for many other issues and items. Extreme weather CAPs are not exceptions and do
not need a new way to solicit feedback. R9.1 should be removed because it also creates a compliance
requirement without any benefit to reliability and would be confusing. In addition, a commenter
requested 9.1 subpart be removed because it creates a compliance requirement without any incremental
benefit to reliability and further conflicts with existing planning requirements and processes. In addition,
some entities felt the way Requirement R9 was drafted out was providing some confusion and requested
re-order of the sub-parts.
Drafting team response
An entity may use what is already in place to be compliant with this requirement. This requirement is
addressing the FERC Order 896 directive in P152 that states “we direct NERC to develop certain processes
to facilitate interaction and coordination with applicable regulatory authorities or governing bodies
responsible for retail electric service as appropriate in implementing a corrective action plan.” Lastly, the
TPL-008-1 Standard is aligning with what the FERC Order 896 directs. The DT did its best to align with TPL001 while meeting the FERC Order 896 directives.
The DT re-order the CAP process within Requirement R9 to provide clarity. Please see the updated
standard.

Include Threshold

One commenter believes the requirement for the notification to an applicable regulatory entity should also
include a threshold. As written, an entity would need to make a notification if a proposal tripped 0.1 MW
of non-consequential load. Recommend the DT add a threshold in a similar way as is included in TPL-001
Attachment 1.
Drafting team response
The DT does not feel that a threshold is needed in the TPL-008-1 Standard. An entity only has report
obligations if it is a part of a CAP. Depending on the mechanism used, you may not be required to report
smaller amounts of load.

Jurisdiction

One commenter expressed that the "applicable regulatory authorities... electric service" needs better
clarification and questioned what this looks like for Jurisdictional vs non-Jurisdictional. The commenter
asked the DT to provide better guidance and examples, and highly recommended using operation

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather | Draft 3
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14

procedures instead of CAPs since operation procedures have more flexibility to respond to a system’s
needs and adapt proactively.
Drafting team response
Per FERC Order 896 P165, building generation and transmission is outside the jurisdiction and left up to
the states. FERC Order 896 provides some examples of various activities that would be appropriate in
P155: “As noted by commenters, the NOPR provided examples of various activities that may be
appropriate under a corrective action plan, some of which may require state or local authorizations (e.g.,
generation or transmission development). Other examples mentioned in the NOPR include
“implementing new energy efficiency programs to decrease load, . . . transmission switching, or adjusting
transmission and generation maintenance outages based on longer-lead forecasts,” none of which involve
the construction of generation or transmission capacity. In addition, responsible entities have the option
to use controlled load shed as a mitigation measure. In sum, while responsible entities would have the
obligation to develop and implement a corrective action plan, the Commission is not directing any specific
result or content of the corrective action plan. In such circumstances, the Commission’s directive does
not exceed the jurisdictional limits set forth in section 215(i) of the FPA0.” Also, "applicable regulatory
authorities or governing bodies responsible for retail electric service issues" is in TPL-001; therefore, the
same entities may be used. Finally, this language was added based on FERC Order 896 P165: “We direct
NERC to require in the new or modified Reliability Standard that responsible entities share their corrective
action plans with, and solicit feedback from, applicable regulatory authorities or governing bodies
responsible for retail electric service issues. We agree with commenters that relevant state entities
should have the opportunity to provide input during the development of corrective action plans. Just as
this final rule seeks to ensure Reliable Operation of the Bulk-Power System during extreme heat and cold
weather events, regulatory authorities and governing bodies responsible for retail electric service are
taking actions to ensure reliability for local stakeholders. As such, we believe that requiring responsible
entities to seek input from applicable regulatory authorities or governing bodies responsible for retail
electric service issues when developing corrective action plans could help ensure that shared
opportunities to increase system reliability are not missed. Further, as NESCOE points out, such
consultation may allow these entities to better understand “the cost implications of various approaches”
and, therefore, provide “better insight into the considerations and tradeoffs inherent in the options
available.”

Requirement R10

Clarity and Communication on Possible Actions

A commenter questioned what actions the responsible entity intends to take based on the identified
"possible actions." There is uncertainty about how these actions will be executed. In addition, the
commenter suggested that these possible actions should be communicated to the operators so they can
prepare necessary plans and processes accordingly.
Drafting team response
The DT acknowledges the commenter's concerns regarding implementing possible actions and their
communication to operators. The DT asserts that R11 outlines the expected actions, mandating responsible

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather | Draft 3
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15

entities to share Extreme Temperature Assessment results with any functional entities that has a reliabilityrelated need to enhance readiness for extreme temperature events.

TPs Ability to Create CAPs

A commenter disagrees with R10 because the requirement does not give TPs the ability to create CAPs for
the listed contingencies.
Drafting team response
Requirement 10 does not preclude Transmission Planners from developing CAPs; however, possible actions
would be required should a Transmission Planner determine that a CAP is not required.

Requirement R11

Timeline for Distributing Assessment Results

Some commenters questioned if the 60 calendar days was appropriate and should align with TPL-001-5 that
states 90-days.
Drafting team response:
The DT determined to keep the requirement unchanged as this strikes a good balance between allowing
enough time for the responsible entity to distribute the results and the functional entity requesting the
information to receive them.

Stability Performance

A commenter asked the DT how to determine stability performance requirements for P0
events. Currently, Table 1 says that the system shall remain stable, and that instability, uncontrolled
separation and cascading shall not occur, but the commenters asked how those would occur for a P0
event.
Drafting team response:
Instability can occur during P0 conditions due to various factors like oscillations, renewable generation
behavior, and excessive power transfers. For example, poorly damped oscillations between generators in
different areas can grow and destabilize the system if not properly controlled. High levels of wind, solar,
or energy storage may also cause instability if these resources don't adequately support grid stability.
Additionally, excessive power transfers on key transmission lines can lead to voltage instability and
potential voltage collapse.

Implementation Plan

One entity disagreed with the amount of time allowed for entities to implement TPL-008-1.
Drafting team response:
The DT appreciates the interest in making the turnaround transition complete in a quicker manner.
However, TPL-008-1 has many factors at play, for example: locating and coordinating with other PCs within
its zone, hosting meetings to determine the common factor that works for all PCs within its zone, etc. The

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16

DT feels it is important to provide entities with adequate time to sort things out with these new
requirements in place to ensure each entity is successful in the end.

Map

A request was made to disconnected portions of SERC and PJM be included into zones that more closely
align with their temperature regions.
Drafting team response:
The “disconnected portions” of PJM and SERC are electrically connected via AC ties and should be studied
together as a zone. In addition, the map is not an accurate depiction, and the disconnected portions are
closer to the PJM and SERC zones than displayed on the map. As a reminder, the map is a visual assistance
and not to be used for compliance purposes.

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather | Draft 3
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17

Update Map and Table 1

Some commenters requested the map be updated to accurately reflect the updated zones.
Drafting team response:
The DT updated the map and Table 1 accordingly.

Coordination via Map and Table 1

One commenter expressed concern with the western portion of the Table and Map. The Table and Map
seem to group together PCs in a way that could create issues when trying to identify which PCs belong to
those zones. There is currently no requirement to post publicly which zone a PC is within, therefore
knowing which PC belongs to each zone is not possible.
Drafting team response:
Coordination with other PCs should be no different than coordinating with the PCs in TPL-001-5. An entity
could reach out to its Regional Entity or coordinate with the larger PC within its zone. The DT recognizes
this may take some time to research and figure out up front but is needed to meet FERC Order 896.

Add State Boundaries to Map

Some commenters support the zones outlined in the map provided in Attachment 1. However, the graphic
would be significantly improved by incorporating state boundaries and referencing the NERC benchmark
library.
Drafting team response:
The DT attempted to add state boundaries and found that the map is not an accurate depiction of zones
when state boundaries are added. This is why Table 1 was developed and the map was added as a visual,
but to be used for compliance purposes.

Technical Rationale

One comment was that the technical rationale states the zones have been determined by the Reliability
Coordinator (RC) area. SPP believes that breaking the zone by RC footprint is not accurate and should be
divided by the PC footprint especially considering that the standard only applies to the PC. PC and RC
footprints can be drastically different across the grid.
Drafting team response:
The DT recognizes this causes confusion and has updated the Technical Rationale to remove RC.
Please see many updates to the Technical Rationale made by the team during this draft.

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather | Draft 3
November 2024

18

Reminder
Standards Announcement

Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather
Additional Ballots and Non-binding Poll Open through October 21, 2024
Now Available

Additional ballots for draft three of TPL-008-1 – Transmission System Planning Performance
Requirements for Extreme Temperature Events and non-binding poll of the associated Violation
Risk Factors and Violation Severity Levels are open through 8 p.m. Eastern, Monday, October 21,
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RELIABILITY | RESILIENCE | SECURITY

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Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Ballot Open Reminder
Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather | October 11, 2024

2

Public

Standards Announcement

Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather
Formal Comment Period Open through October 21, 2024
Now Available

A 15-day formal comment period for draft three of TPL-008-1 – Transmission System Planning
Performance Requirements for Extreme Temperature Events is open through 8 p.m. Eastern,
Monday, October 21, 2024.
The Standards Committee approved waivers to the Standards Process Manual at their December
2023 meeting. These waivers were sought by NERC Standards for reduced formal comment and
ballot periods to assist the drafting teams in expediting the standards development process due to
firm timeline expectations set by FERC Order 896.
The standard drafting team’s considerations of the responses received from the previous comment
period are reflected in this draft of the standard.
Reminder Regarding Corporate RBB Memberships

Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more than
the one permitted representative in a particular Segment must withdraw the duplicate membership(s)
prior to joining new ballot pools or voting on anything as part of an existing ballot pool. Contact
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For more information or assistance, contact Senior Standards Developer, Jordan Mallory (via email) or at
404-479-7358. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists"
from the "Service" drop-down menu and specify “Project 2023-07 Transmission Planning Performance
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Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement
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2

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BALLOT RESULTS  
Comment: View Comment Results (/CommentResults/Index/353)
Ballot Name: 2023-07 Transmission Planning Performance Requirements for Extreme Weather TPL-008-1 AB 3 ST
Voting Start Date: 10/11/2024 12:01:00 AM
Voting End Date: 10/21/2024 8:00:00 PM
Ballot Type: ST
Ballot Activity: AB
Ballot Series: 3
Total # Votes: 265
Total Ballot Pool: 314
Quorum: 84.39
Quorum Established Date: 10/21/2024 5:53:34 PM
Weighted Segment Value: 51.9
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

89

1

33

0.516

31

0.484

0

13

12

Segment:
2

8

0.8

3

0.3

5

0.5

0

0

0

Segment:
3

68

1

28

0.56

22

0.44

0

8

10

Segment:
4

18

1

4

0.4

6

0.6

0

2

6

Segment:
5

76

1

25

0.521

23

0.479

0

13

15

Segment:
6

47

1

23

0.622

14

0.378

0

6

4

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

1

0

0

0

0

0

0

0

1

Segment

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

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:
9

0

0

0

0

0

0

0

0

0

Segment:
10

7

0.4

3

0.3

1

0.1

0

2

1

Totals:

314

6.2

119

3.218

102

2.982

0

44

49

Segment

BALLOT POOL MEMBERS
Show

All

Segment

entries

Organization

Search:

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power,
Inc.

Hillary Creurer

Affirmative

N/A

1

Ameren - Ameren
Services

Tamara Evey

Affirmative

N/A

1

American Transmission
Company, LLC

Amy Wilke

None

N/A

1

APS - Arizona Public
Service Co.

Daniela
Atanasovski

Negative

Comments
Submitted

1

Arizona Electric Power
Cooperative, Inc.

Jennifer Bray

None

N/A

1

Associated Electric
Cooperative, Inc.

Mark Riley

Affirmative

N/A

1

Austin Energy

Thomas
Standifur

None

N/A

Affirmative

N/A

1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Corporation

Segment

Organization

Voter

1

Balancing Authority of
Northern California

Kevin Smith

1

BC Hydro and Power
Authority

1

Designated
Proxy

NERC
Memo

Affirmative

N/A

Adrian Andreoiu

Abstain

N/A

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

Negative

Comments
Submitted

1

Black Hills Corporation

Travis
Grablander

Affirmative

N/A

1

Bonneville Power
Administration

Kamala RogersHolliday

Affirmative

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Negative

Comments
Submitted

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

None

N/A

1

Central Iowa Power
Cooperative

Kevin Lyons

Negative

Third-Party
Comments

1

City Utilities of Springfield,
Missouri

Michael Bowman

Negative

Third-Party
Comments

1

Colorado Springs Utilities

Corey Walker

Negative

Third-Party
Comments

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dairyland Power
Cooperative

Karrie Schuldt

Negative

Third-Party
Comments

1

Dominion - Dominion
Virginia Power

Steven Belle

Negative

Comments
Submitted

1

Duke Energy

Katherine Street

Affirmative

N/A

1

Edison International Southern California
Edison Company

Robert Blackney

Affirmative

N/A

1

Entergy

Brian Lindsey

Affirmative

N/A

1

Evergy

Kevin Frick

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Tim Kelley

Ballot

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Eversource Energy

Joshua London

Affirmative

N/A

1

Exelon

Daniel Gacek

Negative

Comments
Submitted

1

FirstEnergy - FirstEnergy
Corporation

Theresa Ciancio

Affirmative

N/A

1

Georgia Transmission
Corporation

Greg Davis

Negative

Comments
Submitted

1

Glencoe Light and Power
Commission

Terry Volkmann

Negative

Third-Party
Comments

1

Great River Energy

Gordon Pietsch

Negative

Comments
Submitted

1

Hydro One Networks, Inc.

Emma Halilovic

Lidija Efremova

Abstain

N/A

1

Hydro-Quebec (HQ)

Nicolas Turcotte

Chantal Mazza

Abstain

N/A

1

IDACORP - Idaho Power
Company

Sean Steffensen

None

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Denise Sanchez

Affirmative

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Allie Gavin

Negative

Comments
Submitted

1

JEA

Joseph McClung

Affirmative

N/A

1

KAMO Electric
Cooperative

Micah Breedlove

Affirmative

N/A

1

Lakeland Electric

Larry Watt

None

N/A

1

Lincoln Electric System

Josh Johnson

None

N/A

1

Long Island Power
Authority

Isidoro Behar

Abstain

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Abstain

N/A

1

Lower Colorado River
Authority

Matt Lewis

Abstain

N/A

None

N/A

1
LS Power Transmission,
Jennifer
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
LLC
Richardson

Stephen
Stafford

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

M and A Electric Power
Cooperative

William Price

Affirmative

N/A

1

Manitoba Hydro

Nazra Gladu

Affirmative

N/A

1

MEAG Power

David Weekley

Rebika Yitna

Abstain

N/A

1

Minnkota Power
Cooperative Inc.

Theresa Allard

Nikki CarsonMarquis

Negative

Third-Party
Comments

1

Muscatine Power and
Water

Andrew Kurriger

Negative

Third-Party
Comments

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Negative

Comments
Submitted

1

NB Power Corporation

Jeffrey Streifling

Negative

Comments
Submitted

1

Nebraska Public Power
District

Jamison Cawley

Negative

Third-Party
Comments

1

New York Power Authority

Daniel Valle

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service Co.

Alison Nickells

Negative

Comments
Submitted

1

Northeast Missouri
Electric Power
Cooperative

Brett Douglas

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Negative

Third-Party
Comments

1

Omaha Public Power
District

Doug Peterchuck

None

N/A

1

Oncor Electric Delivery

Byron Booker

Negative

Comments
Submitted

1

Orlando Utilities
Commission

Aaron Staley

None

N/A

Negative

Third-Party
Comments

1 - NERC Ver 4.2.1.0
OTP - Machine
Otter TailName:
Power ATLVPEROWEB01
Charles Wicklund
© 2024
Company

Broc Bruton

Segment

Organization

Voter

1

Pacific Gas and Electric
Company

Marco Rios

1

Platte River Power
Authority

1

Designated
Proxy

NERC
Memo

Negative

Comments
Submitted

Marissa Archie

Affirmative

N/A

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Negative

Comments
Submitted

1

Portland General Electric
Co.

Brooke Jockin

Abstain

N/A

1

PPL Electric Utilities
Corporation

Michelle
McCartney
Longo

Affirmative

N/A

1

PSEG - Public Service
Electric and Gas Co.

Karen Arnold

None

N/A

1

Public Utility District No. 1
of Chelan County

Diane E Landry

Negative

Comments
Submitted

1

Public Utility District No. 1
of Snohomish County

Alyssia Rhoads

Negative

Comments
Submitted

1

Public Utility District No. 2
of Grant County,
Washington

Joanne Anderson

Abstain

N/A

1

Sacramento Municipal
Utility District

Wei Shao

Tim Kelley

Affirmative

N/A

1

Salt River Project

Laura Somak

Israel Perez

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Kristine Ward

None

N/A

1

Sempra - San Diego Gas
and Electric

Mohamed
Derbas

Affirmative

N/A

Negative

Comments
Submitted

1

Southern Company Matt Carden
Southern Company
Services, Inc.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Bob Cardle

Ballot

Segment

Organization

Voter

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

1

Tallahassee Electric (City
of Tallahassee, FL)

1

Designated
Proxy

Ballot

NERC
Memo

Abstain

N/A

Negative

Comments
Submitted

Scott Langston

Abstain

N/A

Tennessee Valley
Authority

David Plumb

Negative

Comments
Submitted

1

Tri-State G and T
Association, Inc.

Donna Wood

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Abstain

N/A

1

Unisource - Tucson
Electric Power Co.

Jessica Cordero

Negative

Comments
Submitted

1

VELCO -Vermont Electric
Power Company, Inc.

Randall Buswell

Abstain

N/A

1

Western Area Power
Administration

Ben Hammer

Affirmative

N/A

1

Xcel Energy, Inc.

Eric Barry

Affirmative

N/A

2

California ISO

Darcy O'Connell

Affirmative

N/A

2

Electric Reliability Council
of Texas, Inc.

Kennedy Meier

Negative

Comments
Submitted

2

Independent Electricity
System Operator

Helen Lainis

Negative

Comments
Submitted

2

ISO New England, Inc.

John Pearson

Affirmative

N/A

2

Midcontinent ISO, Inc.

Bobbi Welch

Negative

Comments
Submitted

2

New York Independent
System Operator

Gregory Campoli

Negative

Third-Party
Comments

2

PJM Interconnection,
L.L.C.

Thomas Foster

Elizabeth Davis

Affirmative

N/A

Shannon
Mickens

Negative

Comments
Submitted

2

Southwest Power Pool,
Joshua Phillips
Inc. (RTO)
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Keith Jonassen

Segment

Organization

Voter

3

AEP

Leshel Hutchings

3

Ameren - Ameren
Services

David Jendras Sr

3

APS - Arizona Public
Service Co.

3

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Affirmative

N/A

Jessica Lopez

Negative

Comments
Submitted

Arkansas Electric
Cooperative Corporation

Ayslynn Mcavoy

Abstain

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

Lovita Griffin

Affirmative

N/A

3

Avista - Avista
Corporation

Robert Follini

Affirmative

N/A

3

BC Hydro and Power
Authority

Ming Jiang

Abstain

N/A

3

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Joseph Amato

Negative

Comments
Submitted

3

Black Hills Corporation

Josh Combs

Affirmative

N/A

3

Bonneville Power
Administration

Ron Sporseen

Affirmative

N/A

3

Buckeye Power, Inc.

Tom Schmidt

None

N/A

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Affirmative

N/A

3

City Utilities of Springfield,
Missouri

Jessica
Morrissey

None

N/A

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

None

N/A

3

Colorado Springs Utilities

Hillary Dobson

Negative

Third-Party
Comments

3

Con Ed - Consolidated
Edison Co. of New York

Lincoln Burton

Affirmative

N/A

Negative

Comments
Submitted

3

Dominion - Dominion
Victoria Crider
Virginia Power
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Danielle Moskop

Carly Miller

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

DTE Energy - Detroit
Edison Company

Marvin Johnson

Abstain

N/A

3

Duke Energy - Florida
Power Corporation

Marcelo
Pesantez

Affirmative

N/A

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Entergy

James Keele

Affirmative

N/A

3

Evergy

Marcus Moor

Negative

Comments
Submitted

3

Eversource Energy

Vicki O'Leary

Affirmative

N/A

3

Exelon

Kinte Whitehead

Negative

Comments
Submitted

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

None

N/A

3

Great River Energy

Michael
Brytowski

Negative

Comments
Submitted

3

Imperial Irrigation District

George Kirschner

Affirmative

N/A

3

JEA

Marilyn Williams

None

N/A

3

Lakeland Electric

Steven Marshall

None

N/A

3

Lincoln Electric System

Sam Christensen

Abstain

N/A

3

Los Angeles Department
of Water and Power

Fausto Serratos

Abstain

N/A

3

M and A Electric Power
Cooperative

Gary Dollins

Affirmative

N/A

3

Manitoba Hydro

Mike Smith

Affirmative

N/A

3

MEAG Power

Roger Brand

Abstain

N/A

3

MGE Energy - Madison
Gas and Electric Co.

Benjamin Widder

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Denise Sanchez

Rebika Yitna

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Muscatine Power and
Water

Seth Shoemaker

Negative

Third-Party
Comments

3

National Grid USA

Brian Shanahan

Negative

Comments
Submitted

3

Nebraska Public Power
District

Tony Eddleman

Negative

Third-Party
Comments

3

New York Power Authority

Richard Machado

Affirmative

N/A

3

NextEra Energy - Florida
Power and Light Co.

Karen Demos

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service Co.

Steven
Taddeucci

Negative

Comments
Submitted

3

Northern California Power
Agency

Michael Whitney

None

N/A

3

NW Electric Power
Cooperative, Inc.

Heath Henry

Affirmative

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Negative

Third-Party
Comments

3

Omaha Public Power
District

David Heins

Negative

Third-Party
Comments

3

OTP - Otter Tail Power
Company

Wendi Olson

Negative

Third-Party
Comments

3

Pacific Gas and Electric
Company

Sandra Ellis

Affirmative

N/A

3

Platte River Power
Authority

Richard Kiess

Affirmative

N/A

3

PNM Resources - Public
Service Company of New
Mexico

Amy
Wesselkamper

Negative

Comments
Submitted

3

Portland General Electric
Co.

Mayra Franco

Abstain

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

Negative

Third-Party
Comments

3

PSEG - Public Service
Christopher
ElectricMachine
and GasName:
Co. ATLVPEROWEB01
Murphy
© 2024 - NERC Ver 4.2.1.0

Bob Cardle

Segment

Organization

Voter

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

3

Sacramento Municipal
Utility District

Nicole Looney

3

Salt River Project

Mathew Weber

3

Santee Cooper

3

Designated
Proxy

Ballot

NERC
Memo

Negative

Comments
Submitted

Tim Kelley

Affirmative

N/A

Israel Perez

Affirmative

N/A

Vicky Budreau

Affirmative

N/A

Seminole Electric
Cooperative, Inc.

Usama Tahir

None

N/A

3

Sempra - San Diego Gas
and Electric

Bryan Bennett

Affirmative

N/A

3

Sho-Me Power Electric
Cooperative

Jarrod Murdaugh

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Negative

Third-Party
Comments

3

Southern Company Alabama Power Company

Joel Dembowski

Negative

Comments
Submitted

3

Southern Indiana Gas and
Electric Co.

Ryan Snyder

Abstain

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

John Nierenberg

Negative

Comments
Submitted

3

Tennessee Valley
Authority

Ian Grant

Negative

Comments
Submitted

3

Tri-State G and T
Association, Inc.

Ryan Walter

None

N/A

3

Xcel Energy, Inc.

Nicholas Friebel

None

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Negative

Third-Party
Comments

4

Arkansas Electric
Cooperative Corporation

Jenni Sudduth

None

N/A

4

Austin Energy

Tony Hua

None

N/A

4

Buckeye Power, Inc.

Jason Procuniar

None

N/A

Negative

Third-Party
Comments

4
City Utilities of Springfield,
Jerry Bradshaw
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Missouri

Jennie Wike

Joseph Gatten

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

CMS Energy - Consumers
Energy Company

Aric Root

None

N/A

4

DTE Energy

Patricia Ireland

Abstain

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

Affirmative

N/A

4

Georgia System
Operations Corporation

Katrina Lyons

Negative

Third-Party
Comments

4

North Carolina Electric
Membership Corporation

Richard McCall

Scott Brame

Negative

Third-Party
Comments

4

Northern California Power
Agency

Marty Hostler

Mason Jones

None

N/A

4

Public Utility District No. 1
of Snohomish County

John D.
Martinsen

Negative

Comments
Submitted

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Abstain

N/A

4

Sacramento Municipal
Utility District

Foung Mua

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

George Pino

None

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Negative

Comments
Submitted

4

Utility Services, Inc.

Carver Powers

Affirmative

N/A

4

Western Power Pool

Kevin Conway

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

AES - AES Corporation

Ruchi Shah

None

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Affirmative

N/A

5

APS - Arizona Public
Service Co.

Andrew Smith

Negative

Comments
Submitted

5

Associated Electric
Cooperative, Inc.

Chuck Booth

Affirmative

N/A

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
5
Austin Energy
Michael Dillard

Tim Kelley

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Avista - Avista
Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Quincy Wang

Abstain

N/A

5

Berkshire Hathaway - NV
Energy

Dwanique Spiller

Affirmative

N/A

5

Black Hills Corporation

Sheila Suurmeier

Affirmative

N/A

5

Bonneville Power
Administration

Milli Chennell

Affirmative

N/A

5

Buckeye Power, Inc.

Kevin Zemanek

None

N/A

5

California Department of
Water Resources

ASM Mostafa

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

None

N/A

5

Colorado Springs Utilities

Jeffrey Icke

None

N/A

5

Con Ed - Consolidated
Edison Co. of New York

Michelle Pagano

Affirmative

N/A

5

Constellation

Alison MacKellar

Abstain

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

Dairyland Power
Cooperative

Tommy Drea

Negative

Third-Party
Comments

5

Dominion - Dominion
Resources, Inc.

Barbara Marion

Negative

Comments
Submitted

5

DTE Energy - Detroit
Edison Company

Mohamad
Elhusseini

Abstain

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Selene Willis

Affirmative

N/A

Affirmative

N/A

5
Entergy - Entergy
Gail Golden
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Services, Inc.

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

Hayden Maples

Negative

Comments
Submitted

Affirmative

N/A

5

Evergy

Jeremy Harris

5

FirstEnergy - FirstEnergy
Corporation

Matthew
Augustin

5

Florida Municipal Power
Agency

Chris Gowder

LaKenya
Vannorman

None

N/A

5

Great River Energy

Jacalynn Bentz

Joseph Knight

None

N/A

5

Greybeard Compliance
Services, LLC

Mike Gabriel

Abstain

N/A

5

Grid Strategies LLC

Michael Goggin

Negative

Comments
Submitted

5

Hydro-Quebec (HQ)

Junji Yamaguchi

Chantal Mazza

Abstain

N/A

5

Imperial Irrigation District

Tino Zaragoza

Denise Sanchez

Affirmative

N/A

5

Invenergy LLC

Rhonda Jones

None

N/A

5

JEA

John Babik

Affirmative

N/A

5

Lincoln Electric System

Brittany Millard

Abstain

N/A

5

Los Angeles Department
of Water and Power

Robert Kerrigan

Abstain

N/A

5

Lower Colorado River
Authority

Teresa Krabe

None

N/A

5

LS Power Development,
LLC

C. A. Campbell

None

N/A

5

Manitoba Hydro

Kristy-Lee Young

Affirmative

N/A

5

Muscatine Power and
Water

Chance Back

Negative

Third-Party
Comments

5

National Grid USA

Robin Berry

Negative

Comments
Submitted

5

NB Power Corporation New Brunswick Power
Transmission Corporation

Erin Wilson

Negative

Comments
Submitted

Negative

Third-Party
Comments

5

Nebraska Public Power
Ronald Bender
District
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Helen Zhao

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

New York Power Authority

Zahid Qayyum

Affirmative

N/A

5

NextEra Energy

Richard Vendetti

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service Co.

Kathryn Tackett

Negative

Comments
Submitted

5

North Carolina Electric
Membership Corporation

Reid Cashion

Negative

Third-Party
Comments

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Negative

Third-Party
Comments

5

Oglethorpe Power
Corporation

Donna Johnson

Negative

Third-Party
Comments

5

Omaha Public Power
District

Kayleigh
Wilkerson

Negative

Third-Party
Comments

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Negative

Comments
Submitted

5

Orlando Utilities
Commission

Dania Colon

None

N/A

5

OTP - Otter Tail Power
Company

Stacy Wahlund

Negative

Third-Party
Comments

5

Pacific Gas and Electric
Company

Tyler Brun

Negative

Comments
Submitted

5

Pattern Operators LP

George E Brown

Negative

Third-Party
Comments

5

Platte River Power
Authority

Jon Osell

Affirmative

N/A

5

Portland General Electric
Co.

Ryan Olson

Abstain

N/A

5

PSEG Nuclear LLC

Tim Kucey

None

N/A

5

Public Utility District No. 1
of Chelan County

Rebecca Zahler

Negative

Comments
Submitted

5

Public Utility District No. 1
of Snohomish County

Becky Burden

Negative

Comments
Submitted

Abstain

N/A

5

Public Utility District No. 2
Loren Harbachuk
of Grant County,
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Washington

Scott Brame

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Sacramento Municipal
Utility District

Ryder Couch

Tim Kelley

Affirmative

N/A

5

Salt River Project

Thomas Johnson

Israel Perez

Affirmative

N/A

5

Santee Cooper

Carey Salisbury

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

Melanie Wong

None

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

Leslie Burke

Negative

Comments
Submitted

5

Southern Indiana Gas and
Electric Co.

Larry Rogers

Abstain

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Negative

Comments
Submitted

5

Talen Generation, LLC

Donald Lock

Negative

Comments
Submitted

5

Tallahassee Electric (City
of Tallahassee, FL)

Karen Weaver

Abstain

N/A

5

Tennessee Valley
Authority

Darren Boehm

None

N/A

5

Tri-State G and T
Association, Inc.

Sergio Banuelos

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Kalidass

Abstain

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

AEP

Mathew Miller

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Marcus Bortman

Negative

Comments
Submitted

Affirmative

N/A

6

Associated Electric
Brian Ackermann
Cooperative, Inc.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Austin Energy

Imane Mrini

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Lindsay Wickizer

None

N/A

6

Black Hills Corporation

Rachel Schuldt

Affirmative

N/A

6

Bonneville Power
Administration

Tanner Brier

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Negative

Third-Party
Comments

6

Con Ed - Consolidated
Edison Co. of New York

Jason Chandler

Affirmative

N/A

6

Constellation

Kimberly Turco

Abstain

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Negative

Comments
Submitted

6

Duke Energy

John Sturgeon

Affirmative

N/A

6

Edison International Southern California
Edison Company

Stephanie Kenny

Affirmative

N/A

6

Entergy

Julie Hall

Affirmative

N/A

6

Evergy

Tiffany Lake

Negative

Comments
Submitted

6

FirstEnergy - FirstEnergy
Corporation

Stacey Sheehan

Affirmative

N/A

6

Great River Energy

Brian Meloy

Negative

Comments
Submitted

6

Imperial Irrigation District

Diana Torres

Affirmative

N/A

6

Lakeland Electric

Paul Shipps

Negative

Third-Party
Comments

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

Abstain

N/A

6

Manitoba Hydro

Brandin Stoesz

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Muscatine Power and
Water

Nicholas Burns

Negative

Third-Party
Comments

6

New York Power Authority

Shelly Dineen

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

Affirmative

N/A

6

NiSource - Northern
Indiana Public Service Co.

Rebecca Blair

Negative

Comments
Submitted

6

Northern California Power
Agency

Dennis Sismaet

None

N/A

6

NRG - NRG Energy, Inc.

Martin Sidor

Affirmative

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Ashley F Stringer

Negative

Third-Party
Comments

6

Omaha Public Power
District

Shonda McCain

Negative

Third-Party
Comments

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Stefanie Burke

Abstain

N/A

6

Powerex Corporation

Raj Hundal

Abstain

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade LLC

Laura Wu

None

N/A

6

Public Utility District No. 1
of Chelan County

Tamarra Hardie

Negative

Comments
Submitted

6

Sacramento Municipal
Utility District

Charles Norton

Tim Kelley

Affirmative

N/A

6

Salt River Project

Timothy Singh

Israel Perez

Affirmative

N/A

6

Santee Cooper

Marty Watson

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Bret Galbraith

None

N/A

Negative

Third-Party
Comments

6
Snohomish County PUD
John Liang
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No. 1

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Southern Company Southern Company
Generation and Energy
Marketing

Matthew O'neal

Negative

Comments
Submitted

6

Southern Indiana Gas and
Electric Co.

Kati Barr

Abstain

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

Negative

Comments
Submitted

6

Western Area Power
Administration

Jennifer Neville

Affirmative

N/A

6

Xcel Energy, Inc.

Steve Szablya

Affirmative

N/A

8

Florida Reliability
Coordinating Council –
Member Services Division

Vince Ordax

None

N/A

10

Midwest Reliability
Organization

Mark Flanary

Negative

Comments
Submitted

10

New York State Reliability
Council

Wesley Yeomans

None

N/A

10

Northeast Power
Coordinating Council

Gerry Dunbar

Abstain

N/A

10

ReliabilityFirst

Tremayne Brown

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Abstain

N/A

10

Western Electricity
Coordinating Council

Steven Rueckert

Affirmative

N/A

Jennie Wike

Greg Sorenson

Previous
Showing 1 to 314 of 314 entries

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Comment Forms

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BALLOT RESULTS  
Comment: View Comment Results (/CommentResults/Index/353)
Ballot Name: 2023-07 Transmission Planning Performance Requirements for Extreme Weather Implementation Plan AB 3
OT
Voting Start Date: 10/11/2024 12:01:00 AM
Voting End Date: 10/21/2024 8:00:00 PM
Ballot Type: OT
Ballot Activity: AB
Ballot Series: 3
Total # Votes: 264
Total Ballot Pool: 314
Quorum: 84.08
Quorum Established Date: 10/21/2024 5:57:24 PM
Weighted Segment Value: 63.34

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

89

1

38

0.594

26

0.406

0

13

12

Segment:
2

8

0.8

6

0.6

2

0.2

0

0

0

Segment:
3

68

1

31

0.62

19

0.38

0

8

10

Segment:
4

18

1

5

0.5

5

0.5

0

2

6

Segment:
5

76

1

27

0.574

20

0.426

0

13

16

Segment:
6

47

1

25

0.676

12

0.324

0

6

4

Segment:
7

0

0

0

0

0

0

0

0

0

0

0

0

0

1

Segment

Segment: 1
0
0
0
8
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Negative
Votes w/o
Comment

Abstain

No
Vote

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:
9

0

0

0

0

0

0

0

0

0

Segment:
10

7

0.3

3

0.3

0

0

0

3

1

Totals:

314

6.1

135

3.864

84

2.236

0

45

50

Segment

BALLOT POOL MEMBERS
Show

All

Segment

entries

Organization

Search:

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power,
Inc.

Hillary Creurer

Affirmative

N/A

1

Ameren - Ameren
Services

Tamara Evey

Affirmative

N/A

1

American Transmission
Company, LLC

Amy Wilke

None

N/A

1

APS - Arizona Public
Service Co.

Daniela
Atanasovski

Negative

Comments
Submitted

1

Arizona Electric Power
Cooperative, Inc.

Jennifer Bray

None

N/A

1

Associated Electric
Cooperative, Inc.

Mark Riley

Affirmative

N/A

1

Austin Energy

Thomas
Standifur

None

N/A

Affirmative

N/A

1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Corporation

Segment

Organization

Voter

1

Balancing Authority of
Northern California

Kevin Smith

1

BC Hydro and Power
Authority

1

Designated
Proxy

NERC
Memo

Affirmative

N/A

Adrian Andreoiu

Abstain

N/A

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

Negative

Comments
Submitted

1

Black Hills Corporation

Travis
Grablander

Affirmative

N/A

1

Bonneville Power
Administration

Kamala RogersHolliday

Affirmative

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Negative

Comments
Submitted

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

None

N/A

1

Central Iowa Power
Cooperative

Kevin Lyons

Negative

Third-Party
Comments

1

City Utilities of Springfield,
Missouri

Michael Bowman

Negative

Third-Party
Comments

1

Colorado Springs Utilities

Corey Walker

Negative

Third-Party
Comments

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dairyland Power
Cooperative

Karrie Schuldt

Negative

Third-Party
Comments

1

Dominion - Dominion
Virginia Power

Steven Belle

Negative

Comments
Submitted

1

Duke Energy

Katherine Street

Affirmative

N/A

1

Edison International Southern California
Edison Company

Robert Blackney

Affirmative

N/A

1

Entergy

Brian Lindsey

Affirmative

N/A

1

Evergy

Kevin Frick

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Tim Kelley

Ballot

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Eversource Energy

Joshua London

Affirmative

N/A

1

Exelon

Daniel Gacek

Negative

Comments
Submitted

1

FirstEnergy - FirstEnergy
Corporation

Theresa Ciancio

Affirmative

N/A

1

Georgia Transmission
Corporation

Greg Davis

Affirmative

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Negative

Third-Party
Comments

1

Great River Energy

Gordon Pietsch

Negative

Comments
Submitted

1

Hydro One Networks, Inc.

Emma Halilovic

Lidija Efremova

Abstain

N/A

1

Hydro-Quebec (HQ)

Nicolas Turcotte

Chantal Mazza

Abstain

N/A

1

IDACORP - Idaho Power
Company

Sean Steffensen

None

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Denise Sanchez

Affirmative

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Allie Gavin

Negative

Comments
Submitted

1

JEA

Joseph McClung

Affirmative

N/A

1

KAMO Electric
Cooperative

Micah Breedlove

Affirmative

N/A

1

Lakeland Electric

Larry Watt

None

N/A

1

Lincoln Electric System

Josh Johnson

None

N/A

1

Long Island Power
Authority

Isidoro Behar

Abstain

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Abstain

N/A

1

Lower Colorado River
Authority

Matt Lewis

Abstain

N/A

None

N/A

1
LS Power Transmission,
Jennifer
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
LLC
Richardson

Stephen
Stafford

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

M and A Electric Power
Cooperative

William Price

Affirmative

N/A

1

Manitoba Hydro

Nazra Gladu

Affirmative

N/A

1

MEAG Power

David Weekley

Rebika Yitna

Abstain

N/A

1

Minnkota Power
Cooperative Inc.

Theresa Allard

Nikki CarsonMarquis

Negative

Third-Party
Comments

1

Muscatine Power and
Water

Andrew Kurriger

Negative

Third-Party
Comments

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Negative

Comments
Submitted

1

NB Power Corporation

Jeffrey Streifling

Negative

Comments
Submitted

1

Nebraska Public Power
District

Jamison Cawley

Negative

Third-Party
Comments

1

New York Power Authority

Daniel Valle

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service Co.

Alison Nickells

Negative

Comments
Submitted

1

Northeast Missouri
Electric Power
Cooperative

Brett Douglas

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Negative

Third-Party
Comments

1

Omaha Public Power
District

Doug Peterchuck

None

N/A

1

Oncor Electric Delivery

Byron Booker

Affirmative

N/A

1

Orlando Utilities
Commission

Aaron Staley

None

N/A

Negative

Third-Party
Comments

1

OTP - Otter Tail Power
Charles Wicklund
Company
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Machine Name: ATLVPEROWEB01

Broc Bruton

Segment

Organization

Voter

1

Pacific Gas and Electric
Company

Marco Rios

1

Platte River Power
Authority

1

Designated
Proxy

NERC
Memo

Negative

Comments
Submitted

Marissa Archie

Affirmative

N/A

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Affirmative

N/A

1

Portland General Electric
Co.

Brooke Jockin

Abstain

N/A

1

PPL Electric Utilities
Corporation

Michelle
McCartney
Longo

Affirmative

N/A

1

PSEG - Public Service
Electric and Gas Co.

Karen Arnold

None

N/A

1

Public Utility District No. 1
of Chelan County

Diane E Landry

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Alyssia Rhoads

Negative

Comments
Submitted

1

Public Utility District No. 2
of Grant County,
Washington

Joanne Anderson

Abstain

N/A

1

Sacramento Municipal
Utility District

Wei Shao

Tim Kelley

Affirmative

N/A

1

Salt River Project

Laura Somak

Israel Perez

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Kristine Ward

None

N/A

1

Sempra - San Diego Gas
and Electric

Mohamed
Derbas

Affirmative

N/A

Negative

Comments
Submitted

1

Southern Company Matt Carden
Southern Company
Services, Inc.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Bob Cardle

Ballot

Segment

Organization

Voter

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

1

Tallahassee Electric (City
of Tallahassee, FL)

1

Designated
Proxy

Ballot

NERC
Memo

Abstain

N/A

Affirmative

N/A

Scott Langston

Abstain

N/A

Tennessee Valley
Authority

David Plumb

Negative

Comments
Submitted

1

Tri-State G and T
Association, Inc.

Donna Wood

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Abstain

N/A

1

Unisource - Tucson
Electric Power Co.

Jessica Cordero

Negative

Comments
Submitted

1

VELCO -Vermont Electric
Power Company, Inc.

Randall Buswell

Abstain

N/A

1

Western Area Power
Administration

Ben Hammer

Affirmative

N/A

1

Xcel Energy, Inc.

Eric Barry

Affirmative

N/A

2

California ISO

Darcy O'Connell

Affirmative

N/A

2

Electric Reliability Council
of Texas, Inc.

Kennedy Meier

Affirmative

N/A

2

Independent Electricity
System Operator

Helen Lainis

Affirmative

N/A

2

ISO New England, Inc.

John Pearson

Affirmative

N/A

2

Midcontinent ISO, Inc.

Bobbi Welch

Affirmative

N/A

2

New York Independent
System Operator

Gregory Campoli

Negative

Third-Party
Comments

2

PJM Interconnection,
L.L.C.

Thomas Foster

Elizabeth Davis

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Joshua Phillips

Shannon
Mickens

Negative

Comments
Submitted

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
3
AEP
Leshel Hutchings

Jennie Wike

Keith Jonassen

Segment

Organization

Voter

3

Ameren - Ameren
Services

David Jendras Sr

3

APS - Arizona Public
Service Co.

3

Designated
Proxy

NERC
Memo

Affirmative

N/A

Jessica Lopez

Negative

Comments
Submitted

Arkansas Electric
Cooperative Corporation

Ayslynn Mcavoy

Abstain

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

Lovita Griffin

Affirmative

N/A

3

Avista - Avista
Corporation

Robert Follini

Affirmative

N/A

3

BC Hydro and Power
Authority

Ming Jiang

Abstain

N/A

3

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Joseph Amato

Negative

Comments
Submitted

3

Black Hills Corporation

Josh Combs

Affirmative

N/A

3

Bonneville Power
Administration

Ron Sporseen

Affirmative

N/A

3

Buckeye Power, Inc.

Tom Schmidt

None

N/A

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Affirmative

N/A

3

City Utilities of Springfield,
Missouri

Jessica
Morrissey

None

N/A

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

None

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Lincoln Burton

Affirmative

N/A

3

Dominion - Dominion
Virginia Power

Victoria Crider

Negative

Comments
Submitted

Abstain

N/A

3

DTE Energy - Detroit
Marvin Johnson
Edison Company
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Danielle Moskop

Ballot

Carly Miller

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Duke Energy - Florida
Power Corporation

Marcelo
Pesantez

Affirmative

N/A

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Entergy

James Keele

Affirmative

N/A

3

Evergy

Marcus Moor

Negative

Comments
Submitted

3

Eversource Energy

Vicki O'Leary

Affirmative

N/A

3

Exelon

Kinte Whitehead

Negative

Comments
Submitted

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

None

N/A

3

Great River Energy

Michael
Brytowski

Negative

Comments
Submitted

3

Imperial Irrigation District

George Kirschner

Affirmative

N/A

3

JEA

Marilyn Williams

None

N/A

3

Lakeland Electric

Steven Marshall

None

N/A

3

Lincoln Electric System

Sam Christensen

Abstain

N/A

3

Los Angeles Department
of Water and Power

Fausto Serratos

Abstain

N/A

3

M and A Electric Power
Cooperative

Gary Dollins

Affirmative

N/A

3

Manitoba Hydro

Mike Smith

Affirmative

N/A

3

MEAG Power

Roger Brand

Abstain

N/A

3

MGE Energy - Madison
Gas and Electric Co.

Benjamin Widder

Negative

Third-Party
Comments

3

Muscatine Power and
Water

Seth Shoemaker

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Denise Sanchez

Rebika Yitna

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

National Grid USA

Brian Shanahan

Negative

Comments
Submitted

3

Nebraska Public Power
District

Tony Eddleman

Negative

Third-Party
Comments

3

New York Power Authority

Richard Machado

Affirmative

N/A

3

NextEra Energy - Florida
Power and Light Co.

Karen Demos

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service Co.

Steven
Taddeucci

Negative

Comments
Submitted

3

Northern California Power
Agency

Michael Whitney

None

N/A

3

NW Electric Power
Cooperative, Inc.

Heath Henry

Affirmative

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Negative

Third-Party
Comments

3

Omaha Public Power
District

David Heins

Negative

Third-Party
Comments

3

OTP - Otter Tail Power
Company

Wendi Olson

Negative

Third-Party
Comments

3

Pacific Gas and Electric
Company

Sandra Ellis

Negative

Comments
Submitted

3

Platte River Power
Authority

Richard Kiess

Affirmative

N/A

3

PNM Resources - Public
Service Company of New
Mexico

Amy
Wesselkamper

Affirmative

N/A

3

Portland General Electric
Co.

Mayra Franco

Abstain

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

Christopher
Murphy

Negative

Third-Party
Comments

Affirmative

N/A

3

Public Utility District No. 1
Joyce Gundry
of Chelan
County
© 2024 - NERC Ver 4.2.1.0
Machine
Name: ATLVPEROWEB01

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Sacramento Municipal
Utility District

Nicole Looney

Tim Kelley

Affirmative

N/A

3

Salt River Project

Mathew Weber

Israel Perez

Affirmative

N/A

3

Santee Cooper

Vicky Budreau

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Usama Tahir

None

N/A

3

Sempra - San Diego Gas
and Electric

Bryan Bennett

Affirmative

N/A

3

Sho-Me Power Electric
Cooperative

Jarrod Murdaugh

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Negative

Third-Party
Comments

3

Southern Company Alabama Power Company

Joel Dembowski

Negative

Comments
Submitted

3

Southern Indiana Gas and
Electric Co.

Ryan Snyder

Abstain

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

John Nierenberg

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Negative

Comments
Submitted

3

Tri-State G and T
Association, Inc.

Ryan Walter

None

N/A

3

Xcel Energy, Inc.

Nicholas Friebel

None

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Negative

Third-Party
Comments

4

Arkansas Electric
Cooperative Corporation

Jenni Sudduth

None

N/A

4

Austin Energy

Tony Hua

None

N/A

4

Buckeye Power, Inc.

Jason Procuniar

None

N/A

4

City Utilities of Springfield,
Missouri

Jerry Bradshaw

Negative

Third-Party
Comments

None

N/A

4
CMS Energy - Consumers
Aric Root
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Energy Company

Jennie Wike

Joseph Gatten

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

DTE Energy

Patricia Ireland

Abstain

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

Affirmative

N/A

4

Georgia System
Operations Corporation

Katrina Lyons

Negative

Third-Party
Comments

4

North Carolina Electric
Membership Corporation

Richard McCall

Scott Brame

Negative

Third-Party
Comments

4

Northern California Power
Agency

Marty Hostler

Mason Jones

None

N/A

4

Public Utility District No. 1
of Snohomish County

John D.
Martinsen

Negative

Comments
Submitted

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Abstain

N/A

4

Sacramento Municipal
Utility District

Foung Mua

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

George Pino

None

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

Utility Services, Inc.

Carver Powers

Affirmative

N/A

4

Western Power Pool

Kevin Conway

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

AES - AES Corporation

Ruchi Shah

None

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Affirmative

N/A

5

APS - Arizona Public
Service Co.

Andrew Smith

Negative

Comments
Submitted

5

Associated Electric
Cooperative, Inc.

Chuck Booth

Affirmative

N/A

5

Austin Energy

Michael Dillard

Affirmative

N/A

Affirmative

N/A

5
Avista - Avista
Glen Farmer
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Corporation

Tim Kelley

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

BC Hydro and Power
Authority

Quincy Wang

Abstain

N/A

5

Berkshire Hathaway - NV
Energy

Dwanique Spiller

Affirmative

N/A

5

Black Hills Corporation

Sheila Suurmeier

Affirmative

N/A

5

Bonneville Power
Administration

Milli Chennell

Affirmative

N/A

5

Buckeye Power, Inc.

Kevin Zemanek

None

N/A

5

California Department of
Water Resources

ASM Mostafa

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

None

N/A

5

Colorado Springs Utilities

Jeffrey Icke

None

N/A

5

Con Ed - Consolidated
Edison Co. of New York

Michelle Pagano

Affirmative

N/A

5

Constellation

Alison MacKellar

Abstain

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

Dairyland Power
Cooperative

Tommy Drea

Negative

Third-Party
Comments

5

Dominion - Dominion
Resources, Inc.

Barbara Marion

Negative

Comments
Submitted

5

DTE Energy - Detroit
Edison Company

Mohamad
Elhusseini

Abstain

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Selene Willis

Affirmative

N/A

5

Entergy - Entergy
Services, Inc.

Gail Golden

Affirmative

N/A

Negative

Comments
Submitted

5
Evergy
Jeremy Harris
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Ryan Strom

Hayden Maples

Segment

Organization

Voter

5

FirstEnergy - FirstEnergy
Corporation

Matthew
Augustin

5

Florida Municipal Power
Agency

Chris Gowder

5

Great River Energy

Jacalynn Bentz

5

Greybeard Compliance
Services, LLC

5

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

LaKenya
Vannorman

None

N/A

Joseph Knight

None

N/A

Mike Gabriel

Abstain

N/A

Grid Strategies LLC

Michael Goggin

Negative

Comments
Submitted

5

Hydro-Quebec (HQ)

Junji Yamaguchi

Chantal Mazza

Abstain

N/A

5

Imperial Irrigation District

Tino Zaragoza

Denise Sanchez

Affirmative

N/A

5

Invenergy LLC

Rhonda Jones

None

N/A

5

JEA

John Babik

Affirmative

N/A

5

Lincoln Electric System

Brittany Millard

Abstain

N/A

5

Los Angeles Department
of Water and Power

Robert Kerrigan

Abstain

N/A

5

Lower Colorado River
Authority

Teresa Krabe

None

N/A

5

LS Power Development,
LLC

C. A. Campbell

None

N/A

5

Manitoba Hydro

Kristy-Lee Young

Affirmative

N/A

5

Muscatine Power and
Water

Chance Back

Negative

Third-Party
Comments

5

National Grid USA

Robin Berry

Negative

Comments
Submitted

5

NB Power Corporation New Brunswick Power
Transmission Corporation

Erin Wilson

Negative

Comments
Submitted

5

Nebraska Public Power
District

Ronald Bender

Negative

Third-Party
Comments

5

New York Power Authority

Zahid Qayyum

Affirmative

N/A

Affirmative

N/A

© 2024
Machine
5 - NERC Ver 4.2.1.0
NextEra
EnergyName: ATLVPEROWEB01
Richard Vendetti

Helen Zhao

Segment

Organization

Voter

5

NiSource - Northern
Indiana Public Service Co.

Kathryn Tackett

5

North Carolina Electric
Membership Corporation

Reid Cashion

5

OGE Energy - Oklahoma
Gas and Electric Co.

5

Designated
Proxy

Ballot

NERC
Memo

Negative

Comments
Submitted

Negative

Third-Party
Comments

Patrick Wells

Negative

Third-Party
Comments

Oglethorpe Power
Corporation

Donna Johnson

Negative

Third-Party
Comments

5

Omaha Public Power
District

Kayleigh
Wilkerson

Negative

Third-Party
Comments

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Negative

Comments
Submitted

5

Orlando Utilities
Commission

Dania Colon

None

N/A

5

OTP - Otter Tail Power
Company

Stacy Wahlund

Negative

Third-Party
Comments

5

Pacific Gas and Electric
Company

Tyler Brun

Negative

Comments
Submitted

5

Pattern Operators LP

George E Brown

Negative

Third-Party
Comments

5

Platte River Power
Authority

Jon Osell

Affirmative

N/A

5

Portland General Electric
Co.

Ryan Olson

Abstain

N/A

5

PSEG Nuclear LLC

Tim Kucey

None

N/A

5

Public Utility District No. 1
of Chelan County

Rebecca Zahler

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Becky Burden

Negative

Comments
Submitted

5

Public Utility District No. 2
of Grant County,
Washington

Loren Harbachuk

Abstain

N/A

Affirmative

N/A

5

Sacramento Municipal
Ryder Couch
Utility District
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB01

Scott Brame

Bob Cardle

Tim Kelley

Segment

Organization

Voter

5

Salt River Project

Thomas Johnson

5

Santee Cooper

5

Designated
Proxy

NERC
Memo

Affirmative

N/A

Carey Salisbury

Affirmative

N/A

Seminole Electric
Cooperative, Inc.

Melanie Wong

None

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

Leslie Burke

Negative

Comments
Submitted

5

Southern Indiana Gas and
Electric Co.

Larry Rogers

Abstain

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

Talen Generation, LLC

Donald Lock

None

N/A

5

Tallahassee Electric (City
of Tallahassee, FL)

Karen Weaver

Abstain

N/A

5

Tennessee Valley
Authority

Darren Boehm

None

N/A

5

Tri-State G and T
Association, Inc.

Sergio Banuelos

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Kalidass

Abstain

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

AEP

Mathew Miller

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Marcus Bortman

Negative

Comments
Submitted

6

Associated Electric
Cooperative, Inc.

Brian Ackermann

Affirmative

N/A

6

Austin Energy

Imane Mrini

Affirmative

N/A

None

N/A

6
Berkshire Hathaway Lindsay Wickizer
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PacifiCorp

Israel Perez

Ballot

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Black Hills Corporation

Rachel Schuldt

Affirmative

N/A

6

Bonneville Power
Administration

Tanner Brier

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Negative

Third-Party
Comments

6

Con Ed - Consolidated
Edison Co. of New York

Jason Chandler

Affirmative

N/A

6

Constellation

Kimberly Turco

Abstain

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Negative

Comments
Submitted

6

Duke Energy

John Sturgeon

Affirmative

N/A

6

Edison International Southern California
Edison Company

Stephanie Kenny

Affirmative

N/A

6

Entergy

Julie Hall

Affirmative

N/A

6

Evergy

Tiffany Lake

Negative

Comments
Submitted

6

FirstEnergy - FirstEnergy
Corporation

Stacey Sheehan

Affirmative

N/A

6

Great River Energy

Brian Meloy

Negative

Comments
Submitted

6

Imperial Irrigation District

Diana Torres

Affirmative

N/A

6

Lakeland Electric

Paul Shipps

Negative

Third-Party
Comments

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

Abstain

N/A

6

Manitoba Hydro

Brandin Stoesz

Affirmative

N/A

6

Muscatine Power and
Water

Nicholas Burns

Negative

Third-Party
Comments

6

New York Power Authority

Shelly Dineen

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

Affirmative

N/A

6

NiSource - Northern
Indiana Public Service Co.

Rebecca Blair

Negative

Comments
Submitted

6

Northern California Power
Agency

Dennis Sismaet

None

N/A

6

NRG - NRG Energy, Inc.

Martin Sidor

Affirmative

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Ashley F Stringer

Negative

Third-Party
Comments

6

Omaha Public Power
District

Shonda McCain

Negative

Third-Party
Comments

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Stefanie Burke

Abstain

N/A

6

Powerex Corporation

Raj Hundal

Abstain

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade LLC

Laura Wu

None

N/A

6

Public Utility District No. 1
of Chelan County

Tamarra Hardie

Affirmative

N/A

6

Sacramento Municipal
Utility District

Charles Norton

Tim Kelley

Affirmative

N/A

6

Salt River Project

Timothy Singh

Israel Perez

Affirmative

N/A

6

Santee Cooper

Marty Watson

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Bret Galbraith

None

N/A

6

Snohomish County PUD
No. 1

John Liang

Negative

Comments
Submitted

Negative

Comments
Submitted

6

Southern Company Matthew O'neal
Southern Company
Generation and Energy
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Marketing

Segment

Organization

Voter

6

Southern Indiana Gas and
Electric Co.

Kati Barr

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

6

Western Area Power
Administration

6

Designated
Proxy

Ballot

NERC
Memo

Abstain

N/A

Affirmative

N/A

Jennifer Neville

Affirmative

N/A

Xcel Energy, Inc.

Steve Szablya

Affirmative

N/A

8

Florida Reliability
Coordinating Council –
Member Services Division

Vince Ordax

None

N/A

10

Midwest Reliability
Organization

Mark Flanary

Affirmative

N/A

10

New York State Reliability
Council

Wesley Yeomans

None

N/A

10

Northeast Power
Coordinating Council

Gerry Dunbar

Abstain

N/A

10

ReliabilityFirst

Tremayne Brown

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Abstain

N/A

10

Western Electricity
Coordinating Council

Steven Rueckert

Abstain

N/A

Jennie Wike

Greg Sorenson

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BALLOT RESULTS  
Ballot Name: 2023-07 Transmission Planning Performance Requirements for Extreme Weather TPL-008-1 | Non-binding Poll
AB 3 NB
Voting Start Date: 10/11/2024 12:01:00 AM
Voting End Date: 10/21/2024 8:00:00 PM
Ballot Type: NB
Ballot Activity: AB
Ballot Series: 3
Total # Votes: 249
Total Ballot Pool: 297
Quorum: 83.84
Quorum Established Date: 10/21/2024 5:59:32 PM
Weighted Segment Value: 55.19
Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
1

86

1

28

0.519

26

0.481

19

13

Segment:
2

7

0.4

2

0.2

2

0.2

3

0

Segment:
3

63

1

23

0.561

18

0.439

13

9

Segment:
4

18

1

5

0.5

5

0.5

2

6

Segment:
5

72

1

22

0.537

19

0.463

16

14

Segment:
6

44

1

18

0.6

12

0.4

9

5

Segment:
7

0

0

0

0

0

0

0

0

Segment:
8

1

0

0

0

0

0

0

1

Segment:
9

0

0

0

0

0

0

0

0

Segment

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
10

6

0.3

3

0.3

0

0

3

0

Totals:

297

5.7

101

3.216

82

2.484

65

48

Segment

BALLOT POOL MEMBERS
Show

All

Segment

entries

Organization

Search:

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power,
Inc.

Hillary Creurer

Affirmative

N/A

1

Ameren - Ameren
Services

Tamara Evey

Abstain

N/A

1

American Transmission
Company, LLC

Amy Wilke

None

N/A

1

APS - Arizona Public
Service Co.

Daniela
Atanasovski

Negative

Comments
Submitted

1

Arizona Electric Power
Cooperative, Inc.

Jennifer Bray

None

N/A

1

Associated Electric
Cooperative, Inc.

Mark Riley

Affirmative

N/A

1

Austin Energy

Thomas
Standifur

None

N/A

1

Avista - Avista
Corporation

Mike Magruder

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Tim Kelley

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

BC Hydro and Power
Authority

Adrian Andreoiu

Abstain

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

Negative

Comments
Submitted

1

Black Hills Corporation

Travis
Grablander

Affirmative

N/A

1

Bonneville Power
Administration

Kamala RogersHolliday

Affirmative

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Negative

Comments
Submitted

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

None

N/A

1

Central Iowa Power
Cooperative

Kevin Lyons

Negative

Comments
Submitted

1

City Utilities of Springfield,
Missouri

Michael Bowman

Negative

Comments
Submitted

1

Colorado Springs Utilities

Corey Walker

Negative

Comments
Submitted

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dairyland Power
Cooperative

Karrie Schuldt

Negative

Comments
Submitted

1

Dominion - Dominion
Virginia Power

Steven Belle

Negative

Comments
Submitted

1

Duke Energy

Katherine Street

Affirmative

N/A

1

Edison International Southern California
Edison Company

Robert Blackney

Affirmative

N/A

1

Entergy

Brian Lindsey

Affirmative

N/A

1

Evergy

Kevin Frick

Negative

Comments
Submitted

1

Eversource Energy

Joshua London

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Exelon

Daniel Gacek

Negative

Comments
Submitted

1

FirstEnergy - FirstEnergy
Corporation

Theresa Ciancio

Affirmative

N/A

1

Georgia Transmission
Corporation

Greg Davis

Negative

Comments
Submitted

1

Glencoe Light and Power
Commission

Terry Volkmann

Abstain

N/A

1

Great River Energy

Gordon Pietsch

Negative

Comments
Submitted

1

Hydro One Networks, Inc.

Emma Halilovic

Lidija Efremova

Abstain

N/A

1

Hydro-Quebec (HQ)

Nicolas Turcotte

Chantal Mazza

Abstain

N/A

1

IDACORP - Idaho Power
Company

Sean Steffensen

None

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Denise Sanchez

Affirmative

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Allie Gavin

Negative

Comments
Submitted

1

JEA

Joseph McClung

Affirmative

N/A

1

KAMO Electric
Cooperative

Micah Breedlove

Affirmative

N/A

1

Lakeland Electric

Larry Watt

None

N/A

1

Lincoln Electric System

Josh Johnson

None

N/A

1

Long Island Power
Authority

Isidoro Behar

Abstain

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Abstain

N/A

1

Lower Colorado River
Authority

Matt Lewis

Abstain

N/A

1

LS Power Transmission,
LLC

Jennifer
Richardson

None

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Stephen
Stafford

Segment

Organization

Voter

1

M and A Electric Power
Cooperative

William Price

1

MEAG Power

David Weekley

1

Minnkota Power
Cooperative Inc.

Theresa Allard

1

Muscatine Power and
Water

1

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Rebika Yitna

Abstain

N/A

Nikki CarsonMarquis

Negative

Comments
Submitted

Andrew Kurriger

Negative

Comments
Submitted

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Negative

Comments
Submitted

1

NB Power Corporation

Jeffrey Streifling

Negative

Comments
Submitted

1

Nebraska Public Power
District

Jamison Cawley

Abstain

N/A

1

New York Power Authority

Daniel Valle

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Abstain

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Alison Nickells

Negative

Comments
Submitted

1

Northeast Missouri
Electric Power
Cooperative

Brett Douglas

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Negative

Comments
Submitted

1

Omaha Public Power
District

Doug Peterchuck

None

N/A

1

Oncor Electric Delivery

Byron Booker

Affirmative

N/A

1

Orlando Utilities
Commission

Aaron Staley

None

N/A

1

Pacific Gas and Electric
Company

Marco Rios

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Broc Bruton

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Platte River Power
Authority

Marissa Archie

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Negative

Comments
Submitted

1

Portland General Electric
Co.

Brooke Jockin

Abstain

N/A

1

PPL Electric Utilities
Corporation

Michelle
McCartney
Longo

None

N/A

1

PSEG - Public Service
Electric and Gas Co.

Karen Arnold

None

N/A

1

Public Utility District No. 1
of Chelan County

Diane E Landry

Negative

Comments
Submitted

1

Public Utility District No. 1
of Snohomish County

Alyssia Rhoads

Negative

Comments
Submitted

1

Public Utility District No. 2
of Grant County,
Washington

Joanne Anderson

Abstain

N/A

1

Sacramento Municipal
Utility District

Wei Shao

Tim Kelley

Affirmative

N/A

1

Salt River Project

Laura Somak

Israel Perez

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Abstain

N/A

1

SaskPower

Wayne
Guttormson

Abstain

N/A

1

Seminole Electric
Cooperative, Inc.

Kristine Ward

None

N/A

1

Sempra - San Diego Gas
and Electric

Mohamed
Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Negative

Comments
Submitted

Abstain

N/A

1

Sunflower Electric Power
Paul Mehlhaff
Corporation
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Segment

Organization

Voter

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

1

Tallahassee Electric (City
of Tallahassee, FL)

1

Designated
Proxy

NERC
Memo

Affirmative

N/A

Scott Langston

Abstain

N/A

Tennessee Valley
Authority

David Plumb

Negative

Comments
Submitted

1

Tri-State G and T
Association, Inc.

Donna Wood

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Abstain

N/A

1

Unisource - Tucson
Electric Power Co.

Jessica Cordero

Negative

Comments
Submitted

1

VELCO -Vermont Electric
Power Company, Inc.

Randall Buswell

Abstain

N/A

1

Western Area Power
Administration

Ben Hammer

Affirmative

N/A

2

Electric Reliability Council
of Texas, Inc.

Kennedy Meier

Negative

Comments
Submitted

2

Independent Electricity
System Operator

Helen Lainis

Abstain

N/A

2

ISO New England, Inc.

John Pearson

Affirmative

N/A

2

Midcontinent ISO, Inc.

Bobbi Welch

Abstain

N/A

2

New York Independent
System Operator

Gregory Campoli

Abstain

N/A

2

PJM Interconnection,
L.L.C.

Thomas Foster

Elizabeth Davis

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Joshua Phillips

Shannon
Mickens

Negative

Comments
Submitted

3

AEP

Leshel Hutchings

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras Sr

Abstain

N/A

Negative

Comments
Submitted

3

APS - Arizona Public
Jessica Lopez
Service Co.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Ballot

Keith Jonassen

Danielle Moskop

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Arkansas Electric
Cooperative Corporation

Ayslynn Mcavoy

Abstain

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

Lovita Griffin

Affirmative

N/A

3

Avista - Avista
Corporation

Robert Follini

Affirmative

N/A

3

BC Hydro and Power
Authority

Ming Jiang

Abstain

N/A

3

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Joseph Amato

Negative

Comments
Submitted

3

Black Hills Corporation

Josh Combs

Affirmative

N/A

3

Bonneville Power
Administration

Ron Sporseen

Affirmative

N/A

3

Buckeye Power, Inc.

Tom Schmidt

None

N/A

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Affirmative

N/A

3

City Utilities of Springfield,
Missouri

Jessica
Morrissey

None

N/A

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

None

N/A

3

Colorado Springs Utilities

Hillary Dobson

Negative

Comments
Submitted

3

Con Ed - Consolidated
Edison Co. of New York

Lincoln Burton

Affirmative

N/A

3

Dominion - Dominion
Virginia Power

Victoria Crider

Negative

Comments
Submitted

3

DTE Energy - Detroit
Edison Company

Marvin Johnson

Abstain

N/A

3

Duke Energy - Florida
Power Corporation

Marcelo
Pesantez

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Carly Miller

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Entergy

James Keele

Affirmative

N/A

3

Evergy

Marcus Moor

Negative

Comments
Submitted

3

Eversource Energy

Vicki O'Leary

Affirmative

N/A

3

Exelon

Kinte Whitehead

Negative

Comments
Submitted

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Affirmative

N/A

3

Great River Energy

Michael
Brytowski

Negative

Comments
Submitted

3

Imperial Irrigation District

George
Kirschner

Affirmative

N/A

3

JEA

Marilyn Williams

None

N/A

3

Lakeland Electric

Steven Marshall

None

N/A

3

Lincoln Electric System

Sam Christensen

Abstain

N/A

3

M and A Electric Power
Cooperative

Gary Dollins

Affirmative

N/A

3

MEAG Power

Roger Brand

Abstain

N/A

3

MGE Energy - Madison
Gas and Electric Co.

Benjamin Widder

Negative

Comments
Submitted

3

Muscatine Power and
Water

Seth Shoemaker

Negative

Comments
Submitted

3

National Grid USA

Brian Shanahan

Negative

Comments
Submitted

3

Nebraska Public Power
District

Tony Eddleman

Abstain

N/A

3

New York Power Authority

Richard
Machado

Affirmative

N/A

Abstain

N/A

3
NextEra Energy - Florida
Karen Demos
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Power and Light Co.

Hayden Maples

Denise Sanchez

Rebika Yitna

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

NiSource - Northern
Indiana Public Service
Co.

Steven
Taddeucci

Negative

Comments
Submitted

3

Northern California Power
Agency

Michael Whitney

None

N/A

3

NW Electric Power
Cooperative, Inc.

Heath Henry

Affirmative

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Negative

Comments
Submitted

3

Omaha Public Power
District

David Heins

Negative

Comments
Submitted

3

Pacific Gas and Electric
Company

Sandra Ellis

Negative

Comments
Submitted

3

Platte River Power
Authority

Richard Kiess

Affirmative

N/A

3

PNM Resources - Public
Service Company of New
Mexico

Amy
Wesselkamper

Negative

Comments
Submitted

3

Portland General Electric
Co.

Mayra Franco

Abstain

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

Christopher
Murphy

Abstain

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Negative

Comments
Submitted

3

Sacramento Municipal
Utility District

Nicole Looney

Tim Kelley

Affirmative

N/A

3

Salt River Project

Mathew Weber

Israel Perez

Affirmative

N/A

3

Santee Cooper

Vicky Budreau

Abstain

N/A

3

Seminole Electric
Cooperative, Inc.

Usama Tahir

None

N/A

Affirmative

N/A

3

Sempra - San Diego Gas
Bryan Bennett
and Electric
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB01

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Sho-Me Power Electric
Cooperative

Jarrod Murdaugh

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Negative

Comments
Submitted

3

Southern Company Alabama Power Company

Joel Dembowski

Negative

Comments
Submitted

3

Southern Indiana Gas and
Electric Co.

Ryan Snyder

Abstain

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

John Nierenberg

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Abstain

N/A

3

Tri-State G and T
Association, Inc.

Ryan Walter

None

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Negative

Comments
Submitted

4

Arkansas Electric
Cooperative Corporation

Jenni Sudduth

None

N/A

4

Austin Energy

Tony Hua

None

N/A

4

Buckeye Power, Inc.

Jason Procuniar

None

N/A

4

City Utilities of Springfield,
Missouri

Jerry Bradshaw

Negative

Comments
Submitted

4

CMS Energy - Consumers
Energy Company

Aric Root

None

N/A

4

DTE Energy

Patricia Ireland

Abstain

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

Affirmative

N/A

4

Georgia System
Operations Corporation

Katrina Lyons

Negative

Comments
Submitted

4

North Carolina Electric
Membership Corporation

Richard McCall

Scott Brame

Negative

Comments
Submitted

Mason Jones

None

N/A

4

Northern California Power
Marty Hostler
Agency
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB01

Jennie Wike

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

Public Utility District No. 1
of Snohomish County

John D.
Martinsen

Negative

Comments
Submitted

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Abstain

N/A

4

Sacramento Municipal
Utility District

Foung Mua

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

George Pino

None

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

Utility Services, Inc.

Carver Powers

Affirmative

N/A

4

Western Power Pool

Kevin Conway

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

AES - AES Corporation

Ruchi Shah

None

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Abstain

N/A

5

APS - Arizona Public
Service Co.

Andrew Smith

Negative

Comments
Submitted

5

Associated Electric
Cooperative, Inc.

Chuck Booth

Affirmative

N/A

5

Austin Energy

Michael Dillard

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Quincy Wang

Abstain

N/A

5

Berkshire Hathaway - NV
Energy

Dwanique Spiller

Affirmative

N/A

5

Black Hills Corporation

Sheila Suurmeier

Affirmative

N/A

5

Bonneville Power
Administration

Milli Chennell

Affirmative

N/A

None

N/A

5
Buckeye Power, Inc.
Kevin Zemanek
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Tim Kelley

Jennie Wike

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

California Department of
Water Resources

ASM Mostafa

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

None

N/A

5

Colorado Springs Utilities

Jeffrey Icke

None

N/A

5

Con Ed - Consolidated
Edison Co. of New York

Michelle Pagano

Affirmative

N/A

5

Constellation

Alison MacKellar

Abstain

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

Dairyland Power
Cooperative

Tommy Drea

Negative

Comments
Submitted

5

Dominion - Dominion
Resources, Inc.

Barbara Marion

Negative

No Comment
Submitted

5

DTE Energy - Detroit
Edison Company

Mohamad
Elhusseini

Abstain

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Selene Willis

Affirmative

N/A

5

Entergy - Entergy
Services, Inc.

Gail Golden

Affirmative

N/A

5

Evergy

Jeremy Harris

Negative

Comments
Submitted

5

FirstEnergy - FirstEnergy
Corporation

Matthew
Augustin

Affirmative

N/A

5

Florida Municipal Power
Agency

Chris Gowder

None

N/A

5

Greybeard Compliance
Services, LLC

Mike Gabriel

Abstain

N/A

5

Grid Strategies LLC

Michael Goggin

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

LaKenya
Vannorman

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Hydro-Quebec (HQ)

Junji Yamaguchi

Chantal Mazza

Abstain

N/A

5

Imperial Irrigation District

Tino Zaragoza

Denise Sanchez

Affirmative

N/A

5

JEA

John Babik

Affirmative

N/A

5

Lincoln Electric System

Brittany Millard

Abstain

N/A

5

Los Angeles Department
of Water and Power

Robert Kerrigan

None

N/A

5

Lower Colorado River
Authority

Teresa Krabe

None

N/A

5

LS Power Development,
LLC

C. A. Campbell

None

N/A

5

Muscatine Power and
Water

Chance Back

Negative

Comments
Submitted

5

National Grid USA

Robin Berry

Negative

Comments
Submitted

5

NB Power Corporation New Brunswick Power
Transmission Corporation

Erin Wilson

Negative

Comments
Submitted

5

Nebraska Public Power
District

Ronald Bender

Abstain

N/A

5

New York Power Authority

Zahid Qayyum

Affirmative

N/A

5

NextEra Energy

Richard Vendetti

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Negative

Comments
Submitted

5

North Carolina Electric
Membership Corporation

Reid Cashion

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Negative

Comments
Submitted

5

Oglethorpe Power
Corporation

Donna Johnson

Negative

Comments
Submitted

5

Omaha Public Power
District

Kayleigh
Wilkerson

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Scott Brame

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Negative

Comments
Submitted

5

Orlando Utilities
Commission

Dania Colon

None

N/A

5

OTP - Otter Tail Power
Company

Stacy Wahlund

Negative

Comments
Submitted

5

Pacific Gas and Electric
Company

Tyler Brun

Negative

Comments
Submitted

5

Pattern Operators LP

George E Brown

Negative

Comments
Submitted

5

Platte River Power
Authority

Jon Osell

Affirmative

N/A

5

Portland General Electric
Co.

Ryan Olson

Abstain

N/A

5

PSEG Nuclear LLC

Tim Kucey

None

N/A

5

Public Utility District No. 1
of Chelan County

Rebecca Zahler

Negative

Comments
Submitted

5

Public Utility District No. 1
of Snohomish County

Becky Burden

Negative

Comments
Submitted

5

Public Utility District No. 2
of Grant County,
Washington

Loren Harbachuk

Abstain

N/A

5

Sacramento Municipal
Utility District

Ryder Couch

Tim Kelley

Affirmative

N/A

5

Salt River Project

Thomas Johnson

Israel Perez

Affirmative

N/A

5

Santee Cooper

Carey Salisbury

Abstain

N/A

5

Seminole Electric
Cooperative, Inc.

Melanie Wong

None

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

Leslie Burke

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Bob Cardle

Segment

Organization

Voter

5

Southern Indiana Gas and
Electric Co.

Larry Rogers

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

5

Tallahassee Electric (City
of Tallahassee, FL)

5

Designated
Proxy

Ballot

NERC
Memo

Abstain

N/A

Affirmative

N/A

Karen Weaver

Abstain

N/A

Tennessee Valley
Authority

Darren Boehm

None

N/A

5

Tri-State G and T
Association, Inc.

Sergio Banuelos

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Kalidass

Abstain

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Abstain

N/A

6

AEP

Mathew Miller

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Abstain

N/A

6

APS - Arizona Public
Service Co.

Marcus Bortman

Negative

Comments
Submitted

6

Associated Electric
Cooperative, Inc.

Brian Ackermann

Affirmative

N/A

6

Austin Energy

Imane Mrini

Abstain

N/A

6

Berkshire Hathaway PacifiCorp

Lindsay Wickizer

None

N/A

6

Black Hills Corporation

Rachel Schuldt

Affirmative

N/A

6

Bonneville Power
Administration

Tanner Brier

Affirmative

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Jason Chandler

Affirmative

N/A

6

Constellation

Kimberly Turco

Abstain

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Negative

Comments
Submitted

Affirmative

N/A

6
Duke Energy
John Sturgeon
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Edison International Southern California
Edison Company

Stephanie Kenny

Affirmative

N/A

6

Entergy

Julie Hall

Affirmative

N/A

6

Evergy

Tiffany Lake

Negative

Comments
Submitted

6

FirstEnergy - FirstEnergy
Corporation

Stacey Sheehan

Affirmative

N/A

6

Great River Energy

Brian Meloy

Negative

Comments
Submitted

6

Imperial Irrigation District

Diana Torres

Affirmative

N/A

6

Lakeland Electric

Paul Shipps

Negative

Comments
Submitted

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

Abstain

N/A

6

Muscatine Power and
Water

Nicholas Burns

Negative

Comments
Submitted

6

New York Power Authority

Shelly Dineen

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

Affirmative

N/A

6

NiSource - Northern
Indiana Public Service
Co.

Rebecca Blair

Negative

Comments
Submitted

6

Northern California Power
Agency

Dennis Sismaet

None

N/A

6

NRG - NRG Energy, Inc.

Martin Sidor

Affirmative

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Ashley F Stringer

Negative

Comments
Submitted

6

Omaha Public Power
District

Shonda McCain

Negative

Comments
Submitted

Affirmative

N/A

6

Platte River Power
Sabrina Martz
Authority
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB01

Hayden Maples

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Portland General Electric
Co.

Stefanie Burke

Abstain

N/A

6

Powerex Corporation

Raj Hundal

Abstain

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

PSEG - PSEG Energy
Resources and Trade LLC

Laura Wu

None

N/A

6

Public Utility District No. 1
of Chelan County

Tamarra Hardie

Negative

Comments
Submitted

6

Sacramento Municipal
Utility District

Charles Norton

Tim Kelley

Affirmative

N/A

6

Salt River Project

Timothy Singh

Israel Perez

Affirmative

N/A

6

Santee Cooper

Marty Watson

Abstain

N/A

6

Seminole Electric
Cooperative, Inc.

Bret Galbraith

None

N/A

6

Snohomish County PUD
No. 1

John Liang

Negative

Comments
Submitted

6

Southern Company Southern Company
Generation and Energy
Marketing

Matthew O'neal

Negative

Comments
Submitted

6

Southern Indiana Gas and
Electric Co.

Kati Barr

Abstain

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

Affirmative

N/A

6

Western Area Power
Administration

Jennifer Neville

Affirmative

N/A

8

Florida Reliability
Coordinating Council –
Member Services Division

Vince Ordax

None

N/A

10

Midwest Reliability
Organization

Mark Flanary

Affirmative

N/A

Abstain

N/A

10

Northeast Power
Gerry Dunbar
Coordinating
Council
© 2024 - NERC Ver 4.2.1.0
Machine
Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

10

ReliabilityFirst

Tremayne Brown

10

SERC Reliability
Corporation

10

10

Designated
Proxy
Greg Sorenson

Ballot

NERC
Memo

Affirmative

N/A

Dave Krueger

Affirmative

N/A

Texas Reliability Entity,
Inc.

Rachel Coyne

Abstain

N/A

Western Electricity
Coordinating Council

Steven Rueckert

Abstain

N/A

Previous
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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

This is the fourth draft of the proposed standard posted for a 15-day formal comment period
with additional ballot.
Completed Actions

Date

Standards Committee approved Standard Authorization Request (SAR)
for posting

July 19, 2023

SAR posted for comment

August 8–September 27,
2023

45-day formal comment period with initial ballot

March 20–May 3, 2024

38-day formal comment period with additional ballot

July 16–August 22, 2024

15-day formal comment period with additional ballot

October 7–21, 2024

Anticipated Actions

Date

15-day formal comment period with additional ballot

November 7–21, 2024

5-day final ballot

December 2–6, 2024

Board adoption

December 11, 2024

Draft 4 of TPL-008-1
November 2024

Page 1 of 24

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

New or Modified Term(s) Used in NERC Reliability Standards

This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):

Extreme Temperature Assessment – Documented evaluation of future Bulk Electric System
performance for extreme heat and extreme cold benchmark temperature events.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements for Extreme
Temperature Events

2.

Number:

TPL-008-1

3.

Purpose:

Establish Transmission system planning performance requirements to
develop a Bulk Power System (BPS) that will operate reliably during
extreme heat and extreme cold temperature events.

4.

Applicability:
4.1. Functional Entities:
4.1.1. Transmission Planner
4.1.2. Planning Coordinator

5.

Effective Date: See Implementation Plan for Project 2023-07.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

B. Requirements and Measures
R1. Each Planning Coordinator shall identify, in conjunction with its Transmission
Planner(s), each entity’s individual and joint responsibilities for completing the
Extreme Temperature Assessment, which shall include each of the responsibilities
described in Requirements R2 through R11. Each responsible entity shall complete its
responsibilities such that the Extreme Temperature Assessment is completed at least
once every five calendar years. [Violation Risk Factor: Lower] [Time Horizon: Long-term
Planning]
M1. Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
provide dated documentation of each entity’s individual and joint responsibilities,
such as meeting minutes, agreements, copies of procedures, or protocols in effect
between entities or between departments of a vertically integrated system, or email
correspondence that identifies an agreement has been reached on individual and joint
responsibilities for completing the Extreme Temperature Assessment, and that these
responsibilities were completed such that the Extreme Temperature Assessment was
completed once every five calendar years.
R2. Each Planning Coordinator shall identify the zone(s) to which the Planning Coordinator
belongs to under Attachment 1 and shall coordinate with all Planning Coordinators
within each of its identified zone(s), to identify one common extreme heat benchmark
temperature event and one common extreme cold benchmark temperature event for
each of its identified zone(s) when completing the Extreme Temperature Assessment.
The benchmark temperature events shall be obtained from the benchmark library
maintained by the ERO or developed by the Planning Coordinators. Each benchmark
temperature event shall: [Violation Risk Factor: High] [Time Horizon: Long-term
Planning]
2.1. Consider no less than a 40-year period of temperature data ending no more than
five years prior to the time the benchmark temperature events are selected; and
2.2. Represent one of the 20 most extreme temperature conditions based on the
three-day rolling average of daily maximum (heat) or daily minimum (cold)
temperature across the zone.
M2. Each Planning Coordinator shall have evidence in either electronic or hard copy format
that it identified the zone(s) to which it belongs to, under Attachment 1, and that it
coordinated with all other Planning Coordinators within each of its identified zone(s)
to select one common extreme heat benchmark temperature event and one common
extreme cold benchmark temperature event meeting the criteria of Requirement R2
for each of their identified zone(s) when completing the Extreme Temperature
Assessment.
R3. Each Planning Coordinator shall coordinate with all Planning Coordinators within each
of its zone(s) identified in Requirement R2, to implement a process for developing
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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

benchmark planning cases for the Extreme Temperature Assessment that represent
the benchmark temperature events selected in Requirement R2 and sensitivity cases
to demonstrate the impact of changes to the basic assumptions used in the
benchmark planning cases. This process shall include the following: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
3.1. Selection of System models within the Long-Term Transmission Planning Horizon
to form the basis for the benchmark planning cases.
3.2. Forecasted seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers within the zone.
3.3. Assumed seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers in areas outside the zone, as needed.
3.4. Identification of changes to at least one of the following conditions for sensitivity
cases: generation, real and reactive forecasted Load, or transfers.
M3. Each Planning Coordinator shall have dated evidence that it implemented a process
for coordinating the development of benchmark planning cases and sensitivity cases
for the Extreme Temperature Assessment as specified in Requirement R3.
R4. Each responsible entity, as identified in Requirement R1, shall use the coordination
process developed in Requirement R3 and data consistent with that provided in
accordance with the MOD-032 standard, supplemented by other sources as needed,
to develop the following and establish category P0 as the normal System condition in
Table 1: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. One common extreme heat and one common extreme cold benchmark planning
case.
4.2. One common extreme heat and one common extreme cold sensitivity case.
M4. Each responsible entity, as identified in Requirement R1, shall have dated evidence in
either electronic or hard copy format that it developed benchmark planning cases and
sensitivity cases in accordance with Requirement R4.
R5. Each responsible entity, as identified in Requirement R1, shall have criteria for
acceptable System steady state voltage limits and post-Contingency voltage deviations
for completing the Extreme Temperature Assessment. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning]
M5. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of the documentation, specifying the criteria for
acceptable System steady state voltage limits and post-Contingency voltage deviations
for completing the Extreme Temperature Assessment.
R6. Each responsible entity, as identified in Requirement R1, shall define and document
the criteria or methodology to be used in the Extreme Temperature Assessment to
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identify instability, uncontrolled separation, or Cascading within an Interconnection.
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
M6. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, specifying the criteria or
methodology to be used in the Extreme Temperature Assessment to identify
instability, uncontrolled separation, or Cascading within an Interconnection in
accordance with Requirement R6.
R7. Each responsible entity, as identified in Requirement R1, shall identify the
Contingencies for each category in Table 1 that are expected to produce more severe
System impacts on its portion of the Bulk Electric System. The rationale for those
Contingencies selected for evaluation shall be available as supporting information.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M7. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of the Contingencies for each
category in Table 1 that are expected to produce more severe System impacts on its
portion of the Bulk Electric System along with supporting rationale.
R8. Each responsible entity, as identified in Requirement R1, shall complete steady state
and transient stability analyses in the Extreme Temperature Assessment using the
Contingencies identified in Requirement R7, and shall document the assumptions and
results. Steady state and transient stability analyses shall be performed for the
following: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
8.1. Benchmark planning cases developed in accordance with Requirement R4 Part
4.1.
8.2. Sensitivity cases developed in accordance with Requirement R4 Part 4.2.
M8. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of the assumptions and results of
the steady state and transient stability analyses completed in the Extreme
Temperature Assessment.
R9. Each responsible entity, as identified in Requirement R1, shall develop a Corrective
Action Plan(s) when the analysis of a benchmark planning case, in accordance with
Requirement R8 Part 8.1, indicates its portion of the Bulk Electric System is unable to
meet performance requirements for category P0 or P1 in Table 1. For each Corrective
Action Plan, the responsible entity shall: [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
9.1. Document alternative(s) considered when Non-Consequential Load Loss is
utilized as an element of a Corrective Action Plan for a Table 1 P1 Contingency.
9.2. Be permitted to utilize Non-Consequential Load Loss as an interim solution,
which normally is not permitted for category P0 in Table 1 for situations that are
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beyond the control of the Planning Coordinator or Transmission Planner that
prevent the implementation of a Corrective Action Plan in the required
timeframe, provided that the responsible entity documents the situation causing
the problem, alternatives evaluated, and takes actions to resolve the situation.
9.3. Make its Corrective Action Plan available to, and solicit feedback from, applicable
regulatory authorities or governing bodies responsible for retail electric service
issues.
9.4. Be permitted to have revisions to the Corrective Action Plan in subsequent
Extreme Temperature Assessments, provided that the planned Bulk Electric
System shall continue to meet the performance requirements of Table 1.
M9. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of each Corrective Action Plan
developed in accordance with Requirement R9 when the analysis of a benchmark
planning case indicates its portion of the Bulk Electric System is unable to meet
performance requirements for category P0 or P1 in Table 1. Evidence shall include
documentation of correspondence with applicable regulatory authorities or governing
bodies responsible for retail electric service issues and any revision history.
R10. Each responsible entity, as identified in Requirement R1, shall evaluate and document
possible actions designed to reduce the likelihood or mitigate the consequences and
adverse impacts of the event(s) if analyses conclude there could be instability,
uncontrolled separation, or Cascading within an Interconnection, for the following:
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
10.1. Table 1 P7 Contingencies in benchmark planning cases analyzed in accordance
with Requirement R8 Part 8.1.
10.2. Categories P0, P1, and P7 in Table 1 in sensitivity cases analyzed in accordance
with Requirement R8 Part 8.2.
M10. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation that it evaluated and documented
possible actions designed to reduce the likelihood or mitigate the consequences and
adverse impacts when the analyses conclude there could be instability, uncontrolled
separation, or Cascading within an Interconnection for Table 1 P7 Contingencies in
benchmark planning cases or categories P0, P1, or P7 in Table 1 in sensitivity cases.
R11. Each responsible entity, as identified in Requirement R1, shall provide its Extreme
Temperature Assessment results within 60 calendar days of a request to any
functional entity that has a reliability related need and submits a written request for
the information. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M11. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as email notices, documentation of updated web pages, or postal receipts
showing recipient, that it provided its Extreme Temperature Assessment to any

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functional entity who has a reliability need within 60 calendar days of a written
request.

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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 period(s) 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 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 responsible entity shall retain evidence of compliance with each
requirement in this standard for five calendar years or one complete
Extreme Temperature Assessment cycle, whichever is longer.

1.3. Compliance Monitoring and Enforcement Program: “Compliance Monitoring
Enforcement Program” or “CMEP” means, depending on the context (1) the
NERC Compliance Monitoring and Enforcement Program (Appendix 4C to the
NERC Rules of Procedure) or the Commission-approved program of a Regional
Entity, as applicable, or (2) the program, department or organization within
NERC or a Regional Entity that is responsible for performing compliance
monitoring and enforcement activities with respect to Registered Entities’
compliance with Reliability Standards.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events
Steady State & Stability:
a. Instability, uncontrolled separation, or Cascading within an Interconnection, defined in accordance with Requirement R6,
shall not occur.
b. Consequential Load Loss as well as generation loss is acceptable as a consequence of any event excluding P0.
c. Simulate the removal of all elements that Protection Systems and other controls are expected to automatically disconnect
for each event.
d. Simulate Normal Clearing unless otherwise specified.
e. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such
adjustments are executable within the time duration applicable to the Facility Ratings.
Steady State Only:
f. Applicable Facility Ratings shall not be exceeded.
g. System steady state voltages and post-Contingency voltage deviations shall meet the criteria identified in Requirement R5.

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Table 1 – Steady State & Stability Performance Events

Category

P0
No
Contingency
P1
Single
Contingency

Initial
Condition

Normal
System

Normal
System

P7
Multiple
Contingency
(Common
Structure)

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Normal
System

Event1

Fault
Type3

None

N/A

Loss of one of the following:
1. Generator
2. Transmission Circuit
3. Transformer2
4. Shunt Device4

3Ø

5. Single Pole of a DC line

SLG

The loss of:
1. Any two adjacent (vertically
or horizontally) circuits on
common structure5
2. Loss of a bipolar DC line

SLG

Interruption
of Firm
Contingency
Transmission
BES Level
Service
Allowed

Non-Consequential Load Loss
Allowed
Benchmark
Planning
Cases

Sensitivity
Cases

N/A

Yes

No6

Yes

≥ 200 kV

Yes

Yes6

Yes

≥ 200 kV

Yes

Yes

Yes

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events
1. If the event analyzed involves BES elements at multiple System voltage levels, the lowest System voltage level of the
element(s) removed for the analyzed event determines the BES level of the event. For P7 events, the BES level of the event is
the highest System voltage level of the element(s) removed for the analyzed event.
2. For non-generator step up transformer outage events, the reference voltage, as used in footnote 1, applies to the low-side
winding (excluding tertiary windings). For generator and Generator Step Up transformer outage events, the reference
voltage applies to the BES connected voltage (high-side of the Generator Step Up transformer). Requirements which are
applicable to transformers also apply to variable frequency transformers and phase shifting transformers.
3. Unless specified otherwise, simulate Normal Clearing of faults. Single line to ground (SLG) or three-phase (3Ø) are the fault
types that must be evaluated in Stability simulations for the event described. A 3Ø or a double line to ground fault study
indicating the criteria are being met is sufficient evidence that a SLG condition would also meet the criteria.
4. Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
5. Excludes circuits that share a common structure for 1 mile or less.
6. Benchmark planning cases require the development of a Corrective Action Plan when the responsible entity’s portion of the
BES is unable to meet the performance requirements for categories P0 or P1. Additionally, in benchmark planning cases,
Non-Consequential Load Loss is not permitted for category P0 except where permitted as an interim solution in a Corrective
Action Plan in accordance with Requirement R9 Part 9.2.

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Violation Severity Levels
Violation Severity Levels

R#
R1.

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed less than
or equal to six months late.

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than six months but less than
or equal to 12 months late.

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than 12 months but less than
or equal to 18 months late.

The Planning Coordinator, in
conjunction with its
Transmission Planner(s), failed
to identify individual and joint
responsibilities for completing
the Extreme Temperature
Assessment.
OR
The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than 18 months late.

R2.

N/A

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N/A

The Planning Coordinator
coordinated with all Planning
Coordinators within each
identified zone to identify one
common extreme heat and
one common extreme cold
benchmark temperature event
for completing the Extreme
Temperature Assessment, but
one of the identified events

The Planning Coordinator
coordinated with all Planning
Coordinators within each
identified zone to identify one
common extreme heat and
one common extreme cold
benchmark temperature event
for completing the Extreme
Temperature Assessment, but
both of the identified events

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failed to meet all the criteria of failed to meet all of the criteria
Requirement R2.
of Requirement R2.
OR
The Planning Coordinator
failed to coordinate with all
Planning Coordinators within
each identified zone to identify
one common extreme heat
and one common extreme
cold benchmark temperature
event for completing the
Extreme Temperature
Assessment.
R3.

N/A

N/A

N/A

The Planning Coordinator did
not coordinate with all
Planning Coordinators within
each of its identified zone(s) to
implement a process for
developing benchmark
planning cases.
OR
The Planning Coordinator
coordinated with all Planning
Coordinators within each of its
identified zone(s) to
implement a process for
developing benchmark
planning cases, but the
process did not include all of
the required elements.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R4.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
did not use the coordination
process to develop benchmark
planning cases or sensitivity
cases.
OR
The responsible entity, as
identified in Requirement R1,
used the coordination process
to develop benchmark
planning cases and sensitivity
cases, but did not use data
consistent with that provided
in accordance with the MOD032 standard, supplemented
by other sources as needed,
for one or more of the
required cases.
OR
The responsible entity, as
identified in Requirement R1,
used the coordination process
and data consistent with that
provided in accordance with
the MOD-032 standard,
supplemented as needed, but
failed to develop one or more
of the required planning or
sensitivity cases.

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R5.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
did not have criteria for
acceptable System steady
state voltage limits and postContingency voltage
deviations for completing the
Extreme Temperature
Assessment.

R6.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
failed to define or document
the criteria or methodology to
be used in the Extreme
Temperature Assessment to
identify instability,
uncontrolled separation, or
Cascading within an
Interconnection.

R7.

N/A

N/A

The responsible entity, as
identified in Requirement R1,
identified Contingencies for
each category in Table 1 that
are expected to produce more
severe System impacts on its
portion of the Bulk Electric
System, but did not include
the rationale for those
Contingencies selected for
evaluation as supporting
information.

The responsible entity, as
identified in Requirement R1,
did not identify Contingencies
for each category in Table 1
that are expected to produce
more severe System impacts
on its portion of the Bulk
Electric System.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for
one or more sensitivity cases
in accordance with
Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for
one or more benchmark
planning cases in accordance
with Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
evaluate and document results
for one or more of the
sensitivity cases in accordance
with Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
evaluate and document results
for one or more of the
benchmark planning cases in
accordance with Requirement
R8.
OR
The responsible entity, as
identified in Requirement R1,
failed to complete steady state
or transient stability analyses
and document results in the
Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, in
accordance with Requirement
R8.

R9.

N/A

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N/A

The responsible entity, as
identified in Requirement R1,
developed a Corrective Action
Plan in accordance with
Requirement R9, but failed to
make its Corrective Action
Plan available to, or solicit

The responsible entity, as
identified in Requirement R1,
failed to develop a Corrective
Action Plan when the
benchmark planning case
study results indicate the
System is unable to meet

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

feedback from, applicable
regulatory authorities or
governing bodies responsible
for retail electric service
issues.

R10.

N/A

N/A

The responsible entity, as
identified in Requirement R1,
evaluated and documented
possible actions to reduce the
likelihood or mitigate the
consequences and adverse
impacts of the event(s) when
analyses conclude there could
be instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Part 10.1,
but failed to evaluate and
document possible actions
where required under
Requirement R10 Part 10.2.

performance requirements for
the Table 1 P0 or P1
Contingencies.
OR
The responsible entity, as
identified in Requirement R1,
developed a Corrective Action
Plan, but it was missing one or
more of the elements of
Requirement R9 Part 9.1, 9.3
and 9.4 (as applicable).
The responsible entity, as
identified in Requirement R1,
evaluated and documented
possible actions to reduce the
likelihood or mitigate the
consequences and adverse
impacts of the event(s) when
analyses conclude there could
be instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Part 10.2,
but failed to evaluate and
document possible actions
where required under
Requirement R10 Part 10.1.
OR
The responsible entity, as
identified in Requirement R1,
failed to evaluate and

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document possible actions to
reduce the likelihood or
mitigate the consequences
and adverse impacts of the
event(s) when analyses
conclude there could be
instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Parts 10.1
and 10.2.
R11.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 60 days but
less than or equal to 80 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 80 days but
less than or equal to 100 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 100 days but
less than or equal to 120 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 120 days
following the request.
OR
The responsible entity, as
identified in Requirement R1,
did not provide its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who submitted a written
request for the information.

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D. Regional Variances
None.

E. Associated Documents
•

Implementation Plan for Project 2023-07

•

Technical Rationale Document

•

Consideration of Issues and Directives for FERC Order 896.

•

ERO Benchmark Event Library

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Version History
Version
1

Draft 4 of TPL-008-1
November 2024

Date
TBD

Action

Change
Tracking

Addressing FERC Order 896

New Standard

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TPL-008-1 Supplemental Material

Attachment 1: Extreme Temperature Assessment Zones

The table below lists the zones to be used in the Extreme Temperature Assessment and
identifies the Planning Coordinators that belong to each zone. In accordance with Requirement
R2, each Planning Coordinator is required to identify the zone(s) to which it belongs.
Zone
MISO North

MISO South
SPP North
SPP South
PJM
New England
New York
SERC
Florida
Central Canada
Ontario
Maritimes

WECC Southwest
Pacific Northwest
Great Basin
Rocky Mountain

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Planning Coordinators

Eastern Interconnection
Planning Coordinator(s) in MISO that serve
portions of MISO in Montana, North Dakota,
South Dakota, Minnesota, Iowa, Wisconsin,
Michigan, Indiana, Illinois, Missouri, and
Kentucky
Planning Coordinator(s) in MISO that serve
portions of Arkansas, Mississippi, Louisiana, and
Texas
Planning Coordinator(s) in portions of SPP that
serve Iowa, Montana, Nebraska, North Dakota,
and South Dakota.
Planning Coordinator(s) in portions of SPP that
serve Arkansas, Kansas, Louisiana, Missouri, New
Mexico, Oklahoma, and Texas.
Planning Coordinator(s) that serves PJM
Planning Coordinator(s) in NPCC that serve the six
New England States
Planning Coordinator(s) in NPCC that serve New
York
Planning Coordinator(s) in SERC, excluding those
that serve Florida and those in MISO, SPP, and
PJM
Planning Coordinator(s) in SERC that serve Florida
Planning Coordinator(s) that serve Saskatchewan
and Manitoba region of MRO
Planning Coordinator(s) in NPCC that serve
Ontario
Planning Coordinator(s) in NPCC that primarily
serve New Brunswick, Nova Scotia, Prince Edward
Island, and Northern Maine
Western Interconnection
Planning Coordinator(s) in the Southwest region
of WECC, including El Paso in West Texas
Planning Coordinator(s) in the Pacific Northwest
region of WECC
Planning Coordinator(s) in the Great Basin region
of WECC
Planning Coordinator(s) in the Rocky Mountain
region of WECC
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TPL-008-1 Supplemental Material

California/Mexico
Western Canada
ERCOT
Quebec

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Zone

Planning Coordinators
Planning Coordinator(s) in the California/Mexico
region of WECC
Planning Coordinator(s) that primarily serve
British Columbia and Alberta region of WECC
ERCOT Interconnection
Planning Coordinator(s) in Texas that are part of
the ERCOT Interconnection
Quebec Interconnection
Planning Coordinator(s) that serve Quebec in the
NPCC Region.

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TPL-008-1 Supplemental Material

The map below depicts an approximation of the zones to be used in the Extreme Temperature
Assessment and is provided as a visual aid; to the extent that there is a conflict between the
map and the table, the table controls. This map is not to be used for compliance purposes.
TPL-008-1 Weather Zones Map

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

This is the fourth draft of the proposed standard posted for a 15-day formal comment period
with additional ballot.
Completed Actions

Date

Standards Committee approved Standard Authorization Request (SAR)
for posting

July 19, 2023

SAR posted for comment

August 8–September 27,
2023

45-day formal comment period with initial ballot

March 20–May 3, 2024

38-day formal comment period with additional ballot

July 16–August 22, 2024

15-day formal comment period with additional ballot

October 7–21, 2024

Anticipated Actions

Date

15-day formal comment period with additional ballot

November 7–21, 2024

5-day final ballot

December 2–6, 2024

Board adoption

December 11, 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

New or Modified Term(s) Used in NERC Reliability Standards

This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):

Extreme Temperature Assessment – Documented evaluation of future Bulk Electric System
performance for extreme heat and extreme cold benchmark temperature events.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements for Extreme
Temperature Events

2.

Number:

TPL-008-1

3.

Purpose:

Establish Transmission system planning performance requirements to
develop a Bulk Power System (BPS) that will operate reliably during
extreme heat and extreme cold temperature events.

4.

Applicability:
4.1. Functional Entities:
4.1.1. Transmission Planner
4.1.2. Planning Coordinator

5.

Effective Date: See Implementation Plan for Project 2023-07.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

B. Requirements and Measures
R1. Each Planning Coordinator shall identify, in conjunction with its Transmission
Planner(s), each entity’s individual and joint responsibilities for completing the
Extreme Temperature Assessment, which shall include each of the responsibilities
described in Requirements R2 through R11. Each responsible entity shall complete its
responsibilities such that the Extreme Temperature Assessment is completed at least
once every five calendar years. [Violation Risk Factor: Lower] [Time Horizon: Long-term
Planning]
M1. Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
provide dated documentation of each entity’s individual and joint responsibilities,
such as meeting minutes, agreements, copies of procedures, or protocols, in effect
between entities or between departments of a vertically integrated system, or email
correspondence that identifies an agreement has been reached on individual and joint
responsibilities for completing the Extreme Temperature Assessment, and that these
responsibilities were completed such that the Extreme Temperature Assessment was
completed once every five calendar years.
R2. Each Planning Coordinator shall identify the zone(s) to which the Planning Coordinator
belongs to under Attachment 1, and shall coordinate with all Planning Coordinators
within each of its identified zone(s), to selectidentify one common extreme heat
benchmark temperature event and one common extreme cold benchmark
temperature event for each of its identified zone(s) when completing the Extreme
Temperature Assessment. 1 Selected The benchmark temperature events shall be
obtained from the benchmark library maintained by the ERO or developed by the
Planning Coordinators. Each benchmark temperature event shall: [Violation Risk
Factor: High] [Time Horizon: Long-term Planning]
2.1. Consider no less than a 40-year period of temperature data ending no more than
five years prior to the time the benchmark temperature events are selected; and
2.2. Represent one of the 20 most extreme temperature conditions based on the
three-day rolling average of daily maximum (heat) or daily minimum (cold)
temperature across the zone.
M2. Each Planning Coordinator shall have evidence in either electronic or hard copy format
that it identified the zone(s) to which it belongs to, under Attachment 1, and that it
coordinated with all other Planning Coordinators within each of its identified zone(s)
to select one common extreme heat benchmark temperature event and one common
extreme cold benchmark temperature event meeting the criteria of Requirement R2
for each of their identified zone(s) when completing the Extreme Temperature
Assessment.
1

The Electric Reliability Organization (ERO) will maintain a library of benchmark temperature events that meet the criteria of
Requirement R2.
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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R3. Each Planning Coordinator shall coordinate with all Planning Coordinators within each
of its zone(s) identified in Requirement R2, to implement a process for developing
benchmark planning cases for the Extreme Temperature Assessment that represent
the benchmark temperature events selected in Requirement R2 and sensitivity cases
to demonstrate the impact of changes to the basic assumptions used in the
benchmark planning cases. This process shall include the following: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
3.1. Selection of System models within the Long-Term Transmission Planning Horizon
to form the basis for the benchmark planning cases.
3.2. Forecasted seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers within the zone.
3.3. Assumed seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers in areas outside the zone, as needed.
3.4. Identification of changes to at least one of the following conditions for sensitivity
cases: generation, real and reactive forecasted Load, or transfers.
M3. Each Planning Coordinator shall have dated evidence that it implemented a process
for coordinating the development of benchmark planning cases and sensitivity cases
for the Extreme Temperature Assessment as specified in Requirement R3.
R4. Each responsible entity, as identified in Requirement R1, shall use the coordination
process developed in Requirement R3 and data consistent with that provided in
accordance with the MOD-032 standard, supplemented by other sources as needed,
to develop the following and establish category P0 as the normal System condition in
Table 1: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. One common extreme heat and one common extreme cold benchmark planning
case.
4.2. One common extreme heat and one common extreme cold sensitivity case.
M4. Each responsible entity, as identified in Requirement R1, shall have dated evidence in
either electronic or hard copy format that it developed benchmark planning cases and
sensitivity cases in accordance with Requirement R4.
R5. Each responsible entity, as identified in Requirement R1, shall have criteria for
acceptable System steady state voltage limits and post-Contingency voltage deviations
for completing the Extreme Temperature Assessment. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning]
M5. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of the documentation, specifying the criteria for
acceptable System steady state voltage limits and post-Contingency voltage deviations
for completing the Extreme Temperature Assessment.
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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R6. Each responsible entity, as identified in Requirement R1, shall define and document
the criteria or methodology to be used in the Extreme Temperature Assessment to
identify instability, uncontrolled separation, or Cascading within an Interconnection.
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
M6. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, specifying the criteria or
methodology to be used in the Extreme Temperature Assessment to identify
instability, uncontrolled separation, or Cascading within an Interconnection in
accordance with Requirement R6.
R7. Each responsible entity, as identified in Requirement R1, shall identify the
Contingencies for each category in Table 1 that are expected to produce more severe
System impacts on its portion of the Bulk Electric System. The rationale for those
Contingencies selected for evaluation shall be available as supporting information.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M7. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of the Contingencies for each
category in Table 1 that are expected to produce more severe System impacts on its
portion of the Bulk Electric System along with supporting rationale.
R8. Each responsible entity, as identified in Requirement R1, shall complete steady state
and transient stability analyses in the Extreme Temperature Assessment using the
Contingencies identified in Requirement R7, and shall document the assumptions and
results. Steady state and transient stability analyses shall be performed for the
following: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
8.1. Benchmark planning cases developed in accordance with Requirement R4 Part
4.1.
8.2. Sensitivity cases developed in accordance with Requirement R4 Part 4.2.
M8. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of the assumptions and results of
the steady state and transient stability analyses completed in the Extreme
Temperature Assessment.
R9. Each responsible entity, as identified in Requirement R1, shall develop a Corrective
Action Plan(s) when the analysis of a benchmark planning case, in accordance with
Requirement R8 Part 8.1, indicates its portion of the Bulk Electric System is unable to
meet performance requirements for category P0 or P1 in Table 1. For each Corrective
Action Plan, the responsible entity shall: [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

9.1. Make its Corrective Action Plan available to, and solicit feedback from, applicable
regulatory authorities or governing bodies responsible for retail electric service
issues.
9.2.9.1.
Document alternative(s) considered, and notify the applicable regulatory
authorities or governing bodies responsible for retail electric service issues when
Non-Consequential Load Loss is utilized as an element of a Corrective Action Plan
for a Table 1 P1 Contingency.
9.3.9.2.
Be permitted to utilize Non-Consequential Load Loss as an interim
solution, which normally is not permitted for category P0 in Table 1, in for
situations that are beyond the control of the Planning Coordinator or
Transmission Planner that prevent the implementation of a Corrective Action
Plan in the required timeframe, provided that the responsible entity documents
the situation causing the problem, alternatives evaluated, and takes actions to
resolve the situation.
9.3. Make its Corrective Action Plan available to, and solicit feedback from, applicable
regulatory authorities or governing bodies responsible for retail electric service
issues.
9.4. Be allowedpermitted to have revisions to the Corrective Action Plan in
subsequent Extreme Temperature Assessments, provided that the planned Bulk
Electric System shall continue to meet the performance requirements of Table 1.
M9. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of each Corrective Action Plan
developed in accordance with Requirement R9, including dated documentation of
correspondence with applicable regulatory authorities or governing bodies
responsible for retail electric service issues and any revision history, when the analysis
of a benchmark planning case indicates its portion of the Bulk Electric System is unable
to meet performance requirements for category P0 or P1 in Table 1. Evidence shall
include documentation of correspondence with applicable regulatory authorities or
governing bodies responsible for retail electric service issues and any revision history.
R10. Each responsible entity, as identified in Requirement R1, shall evaluate and document
possible actions designed to reduce the likelihood or mitigate the consequences and
adverse impacts of the event(s) if analyses conclude there could be instability,
uncontrolled separation, or Cascading within an Interconnection, for the following:
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
10.1. Table 1 P7 Contingencies in benchmark planning cases analyzed in accordance
with Requirement R8 Part 8.1.
10.2. Categories P0, P1, and P7 in Table 1 in sensitivity cases analyzed in accordance
with Requirement R8 Part 8.2.
M10. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation that it evaluated and documented
possible actions designed to reduce the likelihood or mitigate the consequences and
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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

adverse impacts when the analyses conclude there could be instability, uncontrolled
separation, or Cascading within an Interconnection for Table 1 P7 Contingencies in
benchmark planning cases or categories P0, P1, or P7 in Table 1 in sensitivity cases.
R11. Each responsible entity, as identified in Requirement R1, shall provide its Extreme
Temperature Assessment results within 60 calendar days of a request to any
functional entity that has a reliability related need and submits a written request for
the information. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M11. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as email notices, documentation of updated web pages, or postal receipts
showing recipient, or a demonstration of a public posting, that it provided its Extreme
Temperature Assessment to any functional entity who has a reliability need within 60
calendar days of a written request.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceablethe NERC
Reliability Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) 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 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 responsible entity shall retain evidence of compliance with each
requirement in this standard for five calendar years or one complete
Extreme Temperature Assessment cycle, whichever is longer.

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring Enforcement Program” or “CMEP”
means, depending on the context (1) the NERC Compliance Monitoring and
Enforcement Program” refers (Appendix 4C to the identificationNERC Rules of
Procedure) or the Commission-approved program of the processesa Regional
Entity, as applicable, or (2) the program, department or organization within
NERC or a Regional Entity that will be used to evaluate data or informationis
responsible for the purpose of assessing performance or outcomesperforming
compliance monitoring and enforcement activities with the associatedrespect to
Registered Entities’ compliance with Reliability StandardStandards.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events
Steady State & Stability:
a. Instability, uncontrolled separation, or Cascading within an Interconnection, defined in accordance with Requirement R6,
shall not occur.
b. Consequential Load Loss as well as generation loss is acceptable as a consequence of any event excluding P0.
c. Simulate the removal of all elements that Protection Systems and other controls are expected to automatically disconnect
for each event.
d. Simulate Normal Clearing unless otherwise specified.
e. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such
adjustments are executable within the time duration applicable to the Facility Ratings.
Steady State Only:
f. Applicable Facility Ratings shall not be exceeded.
g. System steady state voltages and post-Contingency voltage deviations shall meet the criteria identified in Requirement R5.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events

Category

Initial
Condition

Event1

Fault
Type2Type3

Interruption
of Firm
Contingency
Transmission
BES Level
Service
Allowed

Non-Consequential Load
Loss Allowed
Benchmark
Planning
Cases

Sensitivity
Cases
Yes

P0

Normal
No
System
Contingency

P1
Single
Contingency

Normal
System

P7
Multiple
Normal
Contingency System
(Common
Structure)

Draft 4 of TPL-008-1
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None

N/A

Loss of one of the following:
1. Generator
2. Transmission Circuit
3. Transformer3
3. Transformer2
4. Shunt Device4

3Ø

5. Single Pole of a DC line

SLG

The loss of:
1. Any two adjacent
(vertically or horizontally)
circuits on common
structure5
2. Loss of a bipolar DC line

SLG

≥ 200 kVN/A

Yes

No6

≥ 200 kV

Yes

Yes6

≥ 200 kV

Yes

Yes

Yes

Yes

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events
1. If the event analyzed involves BES elements at multiple System voltage levels, the lowest System voltage level of the
element(s) removed for the analyzed event determines the BES level of the event. For P7 events, the BES level of the event is
the highest System voltage level of the element(s) removed for the analyzed event.
2.1. Unless specified otherwise, simulate Normal Clearing of faults. Single line to ground (SLG) or three-phase (3Ø) are the fault
types that must be evaluated in Stability simulations for the event described. A 3Ø or a double line to ground fault study
indicating the criteria are being met is sufficient evidence that a SLG condition would also meet the criteria.
3.2. For non-generator step up transformer outage events, the reference voltage, as used in footnote 1, applies to the low-side
winding (excluding tertiary windings). For generator and Generator Step Up transformer outage events, the reference
voltage applies to the BES connected voltage (high-side of the Generator Step Up transformer). Requirements which are
applicable to transformers also apply to variable frequency transformers and phase shifting transformers.
3. Unless specified otherwise, simulate Normal Clearing of faults. Single line to ground (SLG) or three-phase (3Ø) are the fault
types that must be evaluated in Stability simulations for the event described. A 3Ø or a double line to ground fault study
indicating the criteria are being met is sufficient evidence that a SLG condition would also meet the criteria.
4. Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
5. Excludes circuits that share a common structure for 1 mile or less.
6. Benchmark planning cases require the development of a Corrective Action Plan when the responsible entity’s portion of the
BES is unable to meet the performance requirements for categories P0 or P1. Additionally, in benchmark planning cases,
Non-Consequential Load Loss is not permitted for category P0 and requires notification of applicable regulatory authorities
or governing bodies responsible for retail electric service issues when utilizedexcept where permitted as an element
ofinterim solution in a Corrective Action Plan for P1 Contingencies. Seein accordance with Requirement R9 for the relevant
requirementsPart 9.2.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels
Violation Severity Levels

R#
R1.

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed less than
or equal to six months late.

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than six months but less than
or equal to 12 months late.

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than 12 months but less than
or equal to 18 months late.

The Planning Coordinator, in
conjunction with its
Transmission Planner(s), failed
to identify individual and joint
responsibilities for completing
the Extreme Temperature
Assessment.
OR
The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than 18 months late.

R2.

N/A

Draft 4 of TPL-008-1
November 2024

N/A

The Planning Coordinator
coordinated with all Planning
Coordinators within each
identified zone to
selectidentify one common
extreme heat and one
common extreme cold
benchmark temperature event
for completing the Extreme
Temperature Assessment, but
one of the selectedidentified

The Planning Coordinator
coordinated with all Planning
Coordinators within each
identified zone to
selectidentify one common
extreme heat and one
common extreme cold
benchmark temperature event
for completing the Extreme
Temperature Assessment, but
both of the selectedidentified

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

events failed to meet all the
criteria of Requirement R2.

events failed to meet all of the
criteria of Requirement R2.
OR
The Planning Coordinator
failed to coordinate with all
Planning Coordinators within
each identified zone to
selectidentify one common
extreme heat and one
common extreme cold
benchmark temperature event
for completing the Extreme
Temperature Assessment.

R3.

N/A

N/A

N/A

The Planning Coordinator did
not coordinate with all
Planning Coordinators within
each of its identified zone(s) to
implement a process for
developing benchmark
planning cases.
OR
The Planning Coordinator
coordinated with all Planning
Coordinators within each of its
identified zone(s) to
implement a process for
developing benchmark
planning cases, but the
process did not include all of
the required elements.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R4.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
did not use the coordination
process to develop benchmark
planning cases or sensitivity
cases.
OR
The responsible entity, as
identified in Requirement R1,
used the coordination process
to develop benchmark
planning cases and sensitivity
cases, but did not use data
consistent with that provided
in accordance with the MOD032 standard, supplemented
by other sources as needed,
for one or more of the
required cases.
OR
The responsible entity, as
identified in Requirement R1,
used the coordination process
and data consistent with that
provided in accordance with
the MOD-032 standard,
supplemented as needed, but
failed to develop one or more
of the required planning or
sensitivity cases.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R5.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
did not have criteria for
acceptable System steady
state voltage limits and postContingency voltage
deviations for completing the
Extreme Temperature
Assessment.

R6.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
failed to define or document
the criteria or methodology to
be used in the Extreme
Temperature Assessment to
identify instability,
uncontrolled separation, or
Cascading within an
Interconnection.

R7.

N/A

N/A

The responsible entity, as
identified in Requirement R1,
identified Contingencies for
each category in Table 1 that
are expected to produce more
severe System impacts on its
portion of the Bulk Electric
System, but did not include
the rationale for those
Contingencies selected for
evaluation as supporting
information.

The responsible entity, as
identified in Requirement R1,
did not identify Contingencies
for each category in Table 1
that are expected to produce
more severe System impacts
on its portion of the Bulk
Electric System.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for
one or more sensitivity cases
in accordance with
Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for
one or more benchmark
planning cases in accordance
with Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
evaluate and document results
for one or more of the
sensitivity cases in accordance
with Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
evaluate and document results
for one or more of the
benchmark planning cases in
accordance with Requirement
R8.
OR
The responsible entity, as
identified in Requirement R1,
failed to complete steady state
or transient stability analyses
and document results in the
Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, in
accordance with Requirement
R8.

R9.

N/A

Draft 4 of TPL-008-1
November 2024

N/A

The responsible entity, as
identified in Requirement R1,
developed a Corrective Action
Plan in accordance with
Requirement R9, but failed to
make its Corrective Action
Plan available to, or solicit

The responsible entity, as
identified in Requirement R1,
failed to develop a Corrective
Action Plan when the
benchmark planning case
study results indicate the
System is unable to meet

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

feedback from, applicable
regulatory authorities or
governing bodies responsible
for retail electric service
issues.

R10.

N/A

N/A

The responsible entity, as
identified in Requirement R1,
evaluated and documented
possible actions to reduce the
likelihood or mitigate the
consequences and adverse
impacts of the event(s) when
analyses conclude there could
be instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Part 10.1,
but failed to evaluate and
document possible actions
where required under
Requirement R10 Part 10.2.

performance requirements for
the Table 1 P0 or P1
Contingencies.
OR
The responsible entity, as
identified in Requirement R1,
developed a Corrective Action
Plan, but it was missing one or
more of the elements of
Requirement R9 Part 9.2-1, 9.3
and 9.4 (as applicable).
The responsible entity, as
identified in Requirement R1,
evaluated and documented
possible actions to reduce the
likelihood or mitigate the
consequences and adverse
impacts of the event(s) when
analyses conclude there could
be instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Part 10.2,
but failed to evaluate and
document possible actions
where required under
Requirement R10 Part 10.1.
OR
The responsible entity, as
identified in Requirement R1,
failed to evaluate and

Draft 4 of TPL-008-1
November 2024

Page 18 of 24

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

document possible actions to
reduce the likelihood or
mitigate the consequences
and adverse impacts of the
event(s) when analyses
conclude there could be
instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Parts 10.1
and 10.2.
R11.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 60 days but
less than or equal to 80 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 80 days but
less than or equal to 100 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 100 days but
less than or equal to 120 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 120 days
following the request.
OR
The responsible entity, as
identified in Requirement R1,
did not provide its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who submitted a written
request for the information.

Draft 4 of TPL-008-1
November 2024

Page 19 of 24

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

D. Regional Variances
None.

E. Associated Documents
•

Implementation Plan for Project 2023-07

•

Technical Rationale Document

•

Consideration of Issues and Directives for FERC Order 896.

•

ERO Benchmark Event Library

Draft 4 of TPL-008-1
November 2024

Page 20 of 24

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Version History
Version
1

Draft 4 of TPL-008-1
November 2024

Date
TBD

Action

Change
Tracking

Addressing FERC Order 896

New Standard

Page 21 of 24

TPL-008-1 Supplemental Material

Attachment 1: Extreme Temperature Assessment Zones

The table below lists the zones to be used in the Extreme Temperature Assessment and
identifies the Planning Coordinators that belong to each zone. In accordance with Requirement
R2, each Planning Coordinator is required to identify the zone(s) to which it belongs.
Zone
MISO North

MISO South
SPP North
SPP South
PJM
NPCC (New England)
NPCC (New York)
SERC
SERC (Florida)
Central Canada
Ontario
Eastern CanadaMaritimes

WECC Southwest
Pacific Northwest

Draft 4 of TPL-008-1
November 2024

Planning Coordinators

Eastern Interconnection
MISOPlanning Coordinator(s) in MISO that serve
portions of MISO in Montana, North Dakota,
South Dakota, Minnesota, Iowa, Wisconsin,
Michigan, Indiana, Illinois, Missouri, and
Kentucky
Planning Coordinator(s) in MISO that serve
portions of Arkansas, Mississippi, Louisiana, and
Texas
SPPPlanning Coordinator(s) in portions of SPP
that serve Iowa, Montana, Nebraska, North
Dakota, and South Dakota.
Planning Coordinator(s) in portions of SPP that
serve Arkansas, Kansas, Louisiana, Missouri, New
Mexico, Oklahoma, and Texas.
PJMPlanning Coordinator(s) that serves PJM
Planning CoordinatorsCoordinator(s) in NPCC
that primarily serve the six New England States
Planning CoordinatorsCoordinator(s) in NPCC
that primarily serve New York
Planning CoordinatorsCoordinator(s) in SERC,
excluding those that primarily serve Florida and
those in MISO, SPP, orand PJM
Planning CoordinatorsCoordinator(s) in SERC that
primarily serve Florida
Planning CoordinatorsCoordinator(s) that
primarily serve Saskatchewan and/or Manitoba
region of MRO
Planning Coordinator(s) in NPCC that serve
Ontario
Planning CoordinatorsCoordinator(s) in NPCC
that primarily serve Ontario, New Brunswick, and
Nova Scotia, Prince Edward Island, and Northern
Maine
Western Interconnection
Planning CoordinatorsCoordinator(s) in the
Southwest region of WECC, including El Paso in
West Texas
Planning CoordinatorsCoordinator(s) in the
Pacific Northwest region of WECC

Page 22 of 24

TPL-008-1 Supplemental Material

Great Basin
Rocky Mountain
California/Mexico
Western Canada

ERCOT

Quebec

Draft 4 of TPL-008-1
November 2024

Zone

Planning Coordinators
Planning CoordinatorsCoordinator(s) in the Great
Basin region of WECC
Planning CoordinatorsCoordinator(s) in the Rocky
Mountain region of WECC
Planning CoordinatorsCoordinator(s) in the
California/Mexico region of WECC
Planning CoordinatorsCoordinator(s) that
primarily serve British Columbia and/or Alberta
region of WECC
ERCOT Interconnection
AreasPlanning Coordinator(s) in Texas subject to
ERCOTs jurisdiction.that are part of the ERCOT
Interconnection
Quebec Interconnection
Planning CoordinatorsCoordinator(s) that
primarily serve Quebec in the NPCC Region.

Page 23 of 24

TPL-008-1 Supplemental Material

The map below depicts an approximation of the zones to be used in the Extreme Temperature
Assessment and is provided as a visual aid; to the extent that there is a conflict between the
map and the table, the table controls. This map is not to be used for compliance purposes.

Draft 4 of TPL-008-1
November 2024

Page 24 of 24

Implementation Plan

Project 2023-07 Transmission System Planning Performance
Requirements for Extreme Weather
Reliability Standard TPL-008-1
Applicable Standard
•

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature
Events

Requested Retirement
•

Not applicable

Prerequisite Standard
•

Not applicable

Applicable Entities
•

Planning Coordinators

•

Transmission Planners

New Term in the NERC Glossary of Terms

This section includes all newly defined, revised, or retired terms used or eliminated in the NERC Reliability
Standard. New or revised definitions listed below become approved when the proposed standard is
approved. When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
•

Extreme Temperature Assessment – Documented evaluation of future Bulk Electric System
performance for extreme heat and extreme cold benchmark temperature events.

Background

On June 15, 2023, the U.S. Federal Energy Regulatory Commission (“FERC”) issued Order No. 896, a final
rule directing NERC to develop a new or modified Reliability Standard to address the lack of a long-term
planning requirement(s) for extreme heat and cold weather events. 1 Specifically, FERC directed NERC to
develop modifications to Reliability Standard TPL-001-5.1 or develop a new Reliability Standard that
requires the following: (1) development of benchmark planning cases based on major prior extreme heat
and cold weather events and/or meteorological projections; (2) planning for extreme heat and cold weather
1

Transmission System Planning Requirements for Extreme Weather, Order No. 896, 183 FERC ¶ 61,191 (2023).

RELIABILITY | RESILIENCE | SECURITY

events using steady state and transient stability analyses expanded to cover a range of extreme weather
scenarios including the expected resource mix’s availability during extreme heat and cold weather
conditions, and including the wide-area impacts of extreme heat and cold weather; and (3) development
of Corrective Action Plans that mitigate any instances where performance requirements for extreme heat
and cold weather events are not met. FERC further directed NERC to ensure that the proposed new or
modified Reliability Standard becomes mandatory and enforceable beginning no later than 12 months from
the effective date of FERC approval.

General Considerations

Proposed Reliability Standard TPL-008-1 would require the performance of an Extreme Temperature
Assessment at least once every five calendar years (Requirement R1). This implementation plan provides a
staggered approach for the performance of the first Extreme Temperature Assessment, with phased-in
compliance dates beginning 12 months from the effective date of regulatory approval consistent with Order
No. 896. For subsequent Extreme Temperature Assessments, entities may establish timeframes appropriate
to their facts and circumstances for carrying out their responsibilities under the standard, provided that the
Extreme Temperature Assessment is completed no later than five calendar years following the previous
Extreme Temperature Assessment.

Effective Date

The effective date for the proposed Reliability Standard is provided below. Where the standard drafting
team identified the need for a longer implementation period for compliance with a particular section of the
proposed Reliability Standard (e.g., an entire Requirement or a portion thereof), the additional time for
compliance with that section is specified below. These phased-in compliance dates represent the dates that
entities must begin to comply with that particular section of the Reliability Standard, even where the
Reliability Standard goes into effect at an earlier date.
TPL-008-1 and Definition

Where approval by an applicable governmental authority is required, the standard and definition of
Extreme Temperature Assessment shall become effective on the first day of the first calendar quarter that
is twelve (12) 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 twelve (12) months after the date the standard
and definition of Extreme Temperature Assessment is adopted by the NERC Board of Trustees, or as
otherwise provided for in that jurisdiction.

Phased-In Compliance Dates

Compliance Date for TPL-008-1 Requirement R1

Entities shall be required to comply with Requirement R1, pertaining to the identification of individual and
joint responsibilities for completing the Extreme Temperature Assessment, upon the effective date of
Reliability Standard TPL-008-1.

Implementation Plan
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | November 2024

2

Compliance Date for TPL-008-1 Requirements R2, R3, R4, R5, R6

Entities shall not be required to comply with Requirements R2, R3, R4, R5, and R6 until twenty-four (24)
months after the effective date of Reliability Standard TPL-008-1.
Compliance Date for TPL-008-1 Requirements R7, R8, R9, R10, R11

Entities shall not be required to comply with Requirements R7, R8, R9, R10, and R11 until forty-eight (48)
months after the effective date of Reliability Standard TPL-008-1.
Figure 1: Implementation Plan, Demonstrating Effective Date
and Phased-in Compliance Dates from the effective date of
the governmental authority’s order approving this standard

Initial Performance of Periodic Requirements

Entities shall complete the Extreme Temperature Assessment no later than forty-eight (48) months after
the effective date of Reliability Standard TPL-008-1. Subsequent Extreme Temperature Assessments shall
be completed by no later than five calendar years following the completion of the previous Extreme
Temperature Assessment.

Implementation Plan
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | November 2024

3

Technical Rationale and
Justification for TPL-008-1
Project 2023-07 Transmission Planning
Performance Requirements for Extreme
Weather
November 2024

RELIABILITY | RESILIENCE | SECURITY

NERC | Report Title | Report Date
I

Table of Contents
Preface..................................................................................................................................................................... iii
Introduction ............................................................................................................................................................. iv
Defined Terms........................................................................................................................................................... 5
TPL-008-1 Standard ................................................................................................................................................... 6
Requirement R1 ........................................................................................................................................................ 7
Requirement R2 ........................................................................................................................................................ 8
Requirement R3 ...................................................................................................................................................... 10
Requirement R4 ...................................................................................................................................................... 11
Requirement R5 ...................................................................................................................................................... 12
Requirement R6 ...................................................................................................................................................... 13
Requirement R7 ...................................................................................................................................................... 14
Requirement R8 ...................................................................................................................................................... 19
Requirement R9 ...................................................................................................................................................... 20
Requirement R10 .................................................................................................................................................... 21
Requirement R11 .................................................................................................................................................... 22

NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
ii

Preface
Electricity is a key component of the fabric of modern society and the Electric Reliability Organization (ERO) Enterprise
serves to strengthen that fabric. The vision for the ERO Enterprise, which is comprised of NERC and the six Regional
Entities, is a highly reliable, resilient, and secure North American bulk power system (BPS). Our mission is to assure
the effective and efficient reduction of risks to the reliability and security of the grid.
Reliability | Resilience | Security
Because nearly 400 million citizens in North America are counting on us
The North American BPS is made up of six Regional Entities as shown on the map and in the corresponding table
below. The multicolored area denotes overlap as some load-serving entities participate in one Regional Entity while
associated Transmission Owners/Operators participate in another.

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

Texas RE

Texas Reliability Entity

WECC

WECC

NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
iii

Introduction
This document explains the technical rationale and justification for the proposed Reliability Standard TPL-008-1. It
provides stakeholders and the ERO Enterprise with an understanding of the technology and technical requirements
in the Reliability Standard. This Technical Rationale and Justification for TPL-008-1 is not a Reliability Standard and
should not be considered mandatory and enforceable.

Background

On June 15, 2023, FERC issued FERC Order No. 896 that acknowledges the “challenges associated with planning for
extreme heat and cold weather events, particularly those that occur during periods when the Bulk-Power System
must meet unexpectedly high demand. Extreme heat and cold weather events have occurred with greater frequency
in recent years and are projected to occur with even greater frequency in the future. These events have shown that
load shed during extreme temperatures result in unacceptable risk to life and have extreme economic impact. As
such, the impact of concurrent failures of Bulk-Power System generation and transmission equipment and the
potential for cascading outages that may be caused by extreme heat and cold weather events should be studied and
corrective actions should be identified and implemented.” 1
Therefore, the Commission directed in FERC Order No. 896 to develop a new or modified Reliability Standard to
address a lack of long-term planning requirement(s) for extreme heat and cold weather events. Specifically, FERC
directed NERC to develop modifications to Reliability Standard TPL-001-5.1 or a new Reliability Standard, to require
the following: (1) development of benchmark planning cases based on major prior extreme heat and cold weather
events and/or meteorological projections; (2) planning for extreme heat and cold weather events using steady state
and transient stability analyses expanded to cover a range of extreme weather scenarios including the expected
resource mix's availability during extreme heat and cold weather conditions, and including the wide-area impacts of
extreme heat and cold weather; and (3) development of corrective action plans that mitigate any instances where
performance requirements for extreme heat and cold weather events are not met.

1

N. Am. Elec. Reliability Corp., 183 FERC ¶ 61,191 (2023) (FERC Order), Final Rule. eLibrary | File List (ferc.gov)
NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
iv

Defined Terms
The Standard Drafting Team (SDT) defined one term to be added to the NERC Glossary of Terms to make the
requirements easier to read and understand.
Extreme Temperature Assessment
Documented evaluation of future Bulk Electric System performance for extreme heat and extreme cold
benchmark temperature events.
The definition of Extreme Temperature Assessment was developed by the SDT to limit wordiness throughout the
requirements.

NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
5

TPL-008-1 Standard
The FERC Order No. 896 directed NERC to submit a new Reliability Standard or modifications to Reliability Standard
TPL-001-5.1 to address the concerns pertaining to transmission system planning for extreme heat and cold weather
events that impact the Reliable Operation of the Bulk-Power System.
The SDT determined that a new Reliability Standard was the cleanest way to address FERC’s directives versus
modifying Reliability Standard TPL-001-5.1. While the TPL-008-1 standard uses similar requirements, this allows
industry to have one standard that focuses on extreme heat and extreme cold benchmark temperature events.
The purpose of TPL-008-1 is to “Establish Transmission system planning performance requirements to develop a Bulk
Power System (BPS) that will operate reliably during extreme heat and extreme cold temperature events.” The
directives in FERC Order No. 896 pertain to the reliable operation of the BPS, and the requirements of TPL-008-1
support that by ensuring Planning Coordinators and Transmission Planners are planning their portions of the Bulk
Electric System to meet performance requirements in extreme heat and extreme cold benchmark temperature
events.

NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
6

Requirement R1
Requirement R1 requires each Planning Coordinator (PC) and the Transmission Planner(s) (TP) within the PC’s
footprint to identify each entity’s individual and joint responsibilities when completing the Extreme Temperature
Assessment at least once every five calendar years. Due to significant level of data collection and coordination
between the Planning Coordinator(s) and Transmission Planner(s) for the potential wide-area extreme heat and
extreme cold benchmark events, as well as the need to document the assumptions and study results, the drafting
team opined that completing the Extreme Temperature Assessment once every five calendar years is a reasonable
timeframe to allow responsible entities to coordinate, prepare, perform, and document the study results. To the
extent that responsible entities want to complete more than one set of the Extreme Temperature Assessment for an
extreme heat and extreme cold benchmark event, they can do so, but the minimum requirement is once every five
calendar years to complete one set of the Extreme Temperature Assessment.
The purpose of this requirement is to have the PC and its TP(s) identify their individual and joint responsibilities for
the following activities:
•

Identifying the PC’s zone(s) and coordinating with all PCs in each of its identified zone(s) to select one
common extreme heat benchmark temperature event and one common extreme cold benchmark
temperature event (Requirement R2),

•

Implementing a process for developing benchmark planning cases and sensitivity cases (Requirement R3),

•

Developing benchmark planning cases and sensitivity cases (Requirement R4),

•

Having acceptable criteria (Requirements R5 and R6),

•

Identifying Contingencies for evaluation (Requirement R7),

•

Performing steady state and transient stability analyses (Requirement R8),

•

Developing Corrective Action Plans when required (Requirement R9),

•

Evaluating and documenting possible actions for performance deficiencies that do not require Corrective
Action Plans (Requirement R10), and

•

Providing study results to any functional entity that has a reliability related need (Requirement R11).

The responsibilities described in Requirements R2 and R3 are explicitly assigned to the PC. The responsibilities
described in Requirements R4 through R11 may be completed by either the PC or one or more of its TPs. Requirement
R1 requires that an agreement is reached on the individual and joint responsibilities for completing the Extreme
Temperature Assessment between the PC and its TPs.

NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
7

Requirement R2
Requirement R2 requires each Planning Coordinator (PC) to identify the zone(s) it will participate in for the
components of the Extreme Temperature Assessment that require coordination. PCs in the same zone are required
to coordinate to:
•

Select one common extreme heat benchmark temperature event and one common extreme cold benchmark
temperature event (Requirement R2), and

•

Implement a process for developing benchmark planning cases and sensitivity cases (Requirement R3).

FERC Order No. 896 directed NERC to require that transmission planning studies under the new or revised Reliability
Standard consider the wide-area impacts of extreme heat and cold weather. Considering this directive, the SDT
identified the zones depicted in Attachment 1 as reasonable boundaries that balance the need for studies to cover
large regions with similar weather patterns with the need for a manageable level of coordination. An earlier proposal
to limit coordination to only adjacent PCs was not adequate for meeting FERC’s directives. While the zones depicted
in Attachment 1 will require some PCs to coordinate with many other PCs, the industry has demonstrated, through
various working groups and organizations, that it is capable of cooperating to build models that represent larger
areas. The zones depicted in Attachment 1 are either aligned with existing PC boundaries or boundaries of a group of
PCs with similar weather patterns.
Requirement R2 describes the need to select extreme benchmark temperature events necessary for the creation of
benchmark planning cases. Specifically, extreme hot and cold temperatures experienced during benchmark events
are assumed to be outside the ranges used as the basis of planning cases studied under Reliability Standard TPL-0015.1. Since temperature levels and associated weather conditions affect load levels, generation performance, and
transfer levels, the selection of benchmark events is critical to ensuring the Extreme Temperature Assessment
appropriately evaluates probable System conditions.
Since any region can experience temperatures that are higher or lower than normal, PCs within the same zone must
coordinate to select one common temperature event that includes hotter temperature assumptions and one
common temperature event that includes colder temperature assumptions. While it is understood that, for example,
one region may typically experience hotter summers and milder winters than another region, both a hotter than
average summer and a colder than average winter could result in reliability concerns. Therefore, the requirement is
for one common case specific to extreme heat and one common case specific to extreme cold conditions to be studied
for the Extreme Temperature Assessment. By selecting the same, common events, PCs ensure that extreme
temperatures are studied over the entire zone. The evaluation of a common event taking place over a wide area is
foundational to FERC Order No. 896. Furthermore, selecting the same, common events reasonably limits coordination
requirements. PCs are required to participate in the selection of events for their zone(s), but have no responsibilities
for the selection of events in other zones.
The SDT determined that the extreme heat and extreme cold temperatures selected must have a verified statistical
basis based on weather data from credible sources. The SDT has identified several key features that are used to
determine when a temperature event will constitute a valid extreme benchmark temperature event for the purposes
of completing the Extreme Temperature Assessment. Specifically, extreme benchmark temperature events must:
•

Consider no less than 40 years of temperature data,

•

Utilize data ending no more than five years prior to the time benchmark temperature events are selected,
and

•

Represent one of the worst 20 extreme temperature conditions within the zone.
NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
8

Requirement R2

Temperature events are ranked by computing the 3-day rolling average of daily maximum temperatures (for extreme
heat) or daily minimum temperatures (for extreme cold). The 3-day rolling average temperatures are calculated for
both extreme heat and extreme cold to identify multi-day periods of extreme heat or extreme cold temperature
events. The ERO will maintain a library of benchmark events to provide responsible entities access to vetted
benchmark temperature events that meet the criteria of Requirement R2. While selection of events from the ERO’s
provided library assures entities they are selecting valid events, Requirement R2 does not preclude entities from
collecting temperature data and identifying benchmark temperature events through their own process. Entities that
elect to develop their own benchmark temperature events are responsible for ensuring the input temperature data
and selected benchmark temperature events meet the criteria of Requirement R2. Additionally, because
Requirement R2 requires PCs within a zone to coordinate in the selection of the benchmark temperature events, the
process used to identify these events must be agreeable to those PCs.
The requirement to consider no less than 40 years of temperature data was established based on the observation
that many of the worst events identified in various regions of North America occurred in the 1980s and 1990s. For
example, preliminary data indicated that the five worst extreme cold temperature events in the PJM region over the
last 43 years occurred between 1983 and 1994. Similar results were seen in other regions for both extreme heat and
extreme cold temperature events. Thus, the SDT determined that a minimum of 40 years of temperature data should
be used to ensure more extreme events weren’t excluded by using a shorter duration of temperature data.

NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
9

Requirement R3
Requirement R3 aligns with directives in FERC Order No. 896, emphasizing the importance of coordinating the
development of benchmark planning cases and sensitivity cases amongst PCs within a zone, where the scope of
extreme temperature event studies will likely cover large geographical areas exceeding smaller individual planning
areas. The SDT considered comments from the industry expressing concerns regarding the necessity to coordinate
among all impacted PCs in developing benchmark planning cases and sensitivity cases for various extreme benchmark
temperature events. Recognizing that coordination among all impacted PCs may not be necessary to ensure reliability
within an individual planning area, the SDT drafted Requirement R3 to require each PC to coordinate with all PCs
within a zone to implement a process for the development of benchmark planning cases and sensitivity cases. The
SDT believes this change balances the need to ensure the planning cases capture impacts to/from entities affected
by the same benchmark temperature event, while recognizing that reliability will be less impacted by system changes
far removed from the zone.
PCs within a zone must coordinate to implement a process that results in the development of benchmark planning
cases that represent the benchmark temperature events selected in accordance with Requirement R2, and sensitivity
cases that demonstrate the impact of changes to the basic assumptions used in the benchmark planning cases. This
process requires several components, outlined in the sub-requirements of Requirement R3.
First, Requirement R3 Part 3.1 requires PCs within a zone to identify System models form the basis for developing the
benchmark planning cases. These models must represent one of the years in the Long-Term Transmission Planning
Horizon. PCs will also need to ensure models include stability modeling data to provide for the performance of
stability analysis later in the process. It is reasonably anticipated that PCs will likely utilize a summer peak model as
the starting point for the extreme heat benchmark temperature event and a winter peak model as the starting point
for the extreme cold benchmark temperature event.
Secondly, Requirement R3 Part 3.2 requires that PCs within a zone provide forecasted data for their area within the
zone that represents the benchmark temperature events selected in accordance with Requirement R2. Each PC must
provide data for their area within the zone that represents seasonal and temperature adjustments for Load,
generation, Transmission, and transfers. The provided data should be used to update the starting point models to
reflect the selected benchmark temperature events.
Thirdly, Requirement R3 Part 3.3 allows PCs to agree on assumptions for seasonal and temperature adjustments for
Load, generation, Transmission, and transfers in areas outside of the zone. As a sub-requirement of Requirement R3,
these assumptions must be coordinated among PCs in the zone, as needed. As an example, PCs within the zone may
identify the need for imported power during a benchmark event. The PCs may evaluate historical import availability
and assume an import from an area outside of the zone is reasonable and should be modeled.
Finally, Requirement R3 Part 3.4 requires PCs to coordinate and identify changes to generation, real and reactive
forecasted Load, or transfers that should be reflected in sensitivity cases. Sensitivity cases are intended to
demonstrate the impact of changes to the basic assumptions used in the benchmark planning cases, and Requirement
R3 Part 3.4 ensures PCs are cooperating to identify changes that sufficiently alter the assumptions reflected in the
benchmark planning cases. For example, PCs that identified an import external source to the zone for a benchmark
planning case may elect to alter the source of that import in the sensitivity case.

NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
10

Requirement R4
The SDT drafted Requirement R4 to require the responsible entity to use data consistent with Reliability Standard
MOD-032, supplemented by other sources as needed, for developing benchmark planning cases that represent
System conditions based on selected benchmark temperature events. This aligns with directives in FERC Order No.
896, paragraph 30, emphasizing the requirement of developing both benchmark planning cases and sensitivity study
cases. Requirement R4 is consistent with Reliability Standard TPL-001-5.1 in cross-referencing Reliability Standard
MOD-032, which establishes consistent modeling data requirements and reporting procedures for the development
of planning horizon cases necessary to support analysis of the reliability of the interconnected System. It is also
consistent with Reliability Standard TPL-001-5.1 in acknowledging that data from other sources may be required to
supplement the data collected through Reliability Standard MOD-032 procedures.
Requirement R4 requires entities to use the coordination process developed in accordance with Requirement R3 to
develop the following four cases:
•

One common extreme heat benchmark planning case (Requirement R4 Part 4.1),

•

One common extreme cold benchmark planning case (Requirement R4 Part 4.1),

•

One common extreme heat sensitivity case (Requirement R4 Part 4.2), and

•

One common extreme cold sensitivity case (Requirement R4 Part 4.2).

At the completion of the case development process, implemented in accordance with Requirement R3, and executed
in Requirement R4, responsible entities will have the four cases listed above. This establishes category P0 as the
normal System condition in Table 1 for each case. Requirement R3 does not preclude PCs from implementing a
process that develops cases for multiple benchmark temperature events or additional sensitivity cases. Moreover,
entities may elect to develop additional cases for their internal use.
As per FERC Order No. 896, paragraph 94, it is clarified that resource adequacy benchmarks are not within the scope
of TPL-008-1. The intent of the standard is to evaluate benchmark events where sufficient generation is available to
supply load. However, under an extreme heat or extreme cold temperature condition, there may be instances where
the benchmark planning cases and/or sensitivity cases may not have sufficient available generation to supply the
load. In these scenarios, it may be acceptable for the responsible entity to revise the model to reduce the forecasted
Load, or include forecasted generation, to achieve a solution for the benchmark planning cases and/or sensitivity
cases and evaluate future Bulk Electric System performance for extreme temperature events. Each responsible entity,
as identified in Requirement R1, shall have dated evidence in either electronic or hard copy format that it developed
benchmark planning cases and sensitivity cases in accordance with Requirement R4.

NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
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Requirement R5
Requirement R5 was drafted to require each responsible entity to set the criteria needed for limits that will be used
to evaluate System steady state voltage and post-Contingency voltage deviations for completing the Extreme
Temperature Assessment. The establishment of these criteria allows auditors to compare the results of the Extreme
Temperature Assessment with the established criteria.

NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
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Requirement R6
Requirement R6 was drafted to require the responsible entity to define and document the criteria or methodology
used in evaluating the Extreme Temperature Assessment analysis to identify instability, uncontrolled separation, or
Cascading within an Interconnection. Adequate and thorough criteria should be built into the Extreme Temperature
Assessment to help identify instability, uncontrolled separation, and Cascading conditions. The establishment of
these criteria allows auditors to compare the results of the Extreme Temperature Assessment with the established
criteria.

NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
13

Requirement R7
This requirement addresses directives in FERC Order No. 896 to define a set of Contingencies that responsible entities
will be required to consider when conducting wide-area studies of extreme heat and cold weather events. FERC’s
preference to rely on established Contingency definitions, “[w]e believe that it is necessary to establish a set of
common contingencies for all responsible entities to analyze. Required contingencies, such as those listed in Table 1
of Reliability Standard TPL-001-5.1 (i.e., category P1 through P7), establish common planning events that set the
starting point for transmission system planning assessments,” was also considered by the SDT. It is necessary to
establish a set of common Contingencies for all responsible entities to analyze. Requiring the study of predefined
Contingencies, such as those listed in Table 1, will ensure a level of uniformity across planning regions, considering
that extreme heat and cold weather events often exceed the geographic boundaries of most existing planning
footprints. Defining the Contingencies in Table 1 consistently with Table 1 of Reliability Standard TPL-001-5.1 meets
FERC’s preference for commonality.
If feasible, all Contingencies listed in Table 1 should be considered for evaluation by the responsible entity; however,
the language affords flexibility in identifying the most appropriate Contingencies. As such, the responsible entity
should implement a method and establish sufficient supporting rationale to ensure Contingencies within each
category of Table 1, that are expected to produce more severe System impacts within its planning area, are
adequately identified. It is noted that since the benchmark planning cases are developed from the extreme
temperature benchmark events, they already represent extreme System conditions and thus not all Contingencies
from Reliability Standard TPL-001-5.1 Table 1 are included in the TPL-008-1 Table 1 for assessment. The Events
included in TPL-008-1 Table 1 represent the more likely Contingencies to occur.
The SDT included categories P0, P1, and P7 in Table 1 of TPL-008-1. The SDT finds it reasonable to exclude P2, P3, P4,
P5 and P6 Contingencies from the Extreme Temperature Assessment. Studying categories P0, P1 and P7 is the
minimum requirement of TPL-008-1. The standard does not preclude entities from studying additional Contingencies
if desired. The following discusses the rationale for excluding P2 through P6 Contingencies for TPL-008-1:
1. Excluding P2 and P4 Contingencies:
After consideration of comments received from the industry, the SDT removed P2 and P4 Contingencies due
to lower probability of occurrence than P1 and P7 Contingencies. The standard establishes minimum
requirement for Contingencies with higher probability of occurrence. To the extent that the responsible
entity determines the need for studying beyond the minimum requirements, the standard does not preclude
the entity from doing so.
2. Excluding P3 and P6 Contingencies:
Part of the decision stems from the complexity of P3 and P6 Contingencies, which involve multiple element
outages triggered by multiple Contingencies, with System adjustments allowed between them.
Consequently, the occurrence likelihood of P3 and P6 Contingencies could be even lower compared to P1
and P7 Contingencies. Moreover, aligning with the directives set forth in FERC Order 896, which emphasizes
the importance of incorporating derated generation, transmission capacity, and the availability of generation
and transmission in the development of benchmark planning cases, it becomes imperative for responsible
entities to consider potential concurrent or correlated generation and transmission outages and/or derates
within relevant benchmark planning cases. This ensures that the benchmark planning case accurately reflects
System conditions under extreme temperatures, with generation and transmission derates and/or outages
already factored. Therefore, the SDT believes excluding P3 and P6 is justified, as generation and transmission
derates and/or outages are already accounted for within the benchmark planning cases. Excluding P5
Contingencies:
NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
15

Requirement 7

After consideration of comments received from the industry, the SDT removed P5 Contingency (Delayed Fault
Clearing due to failure of non-redundant component of a Protection System). This is because while some
categories of Contingencies may be assessed in a straightforward approach, category P5 Contingency events
often require a significant level of engineering analysis (including protection and/or control analysis). These
analyses are sensitive to the System topology and expected dispatch. As the planning benchmark cases are
developed for TPL-008-1 that represent System conditions that are different than the typical summer or
winter peak conditions, the development of category P5 Contingency events is expected to be a significant
burden. Since these events only require evaluations of possible mitigations (and not Corrective Action Plans),
violations resulting from these events are unlikely to result in significant transmission System investment.
Furthermore, any violations resulting from category P5 events may be mitigated by eliminating and
addressing the single point of failure included in the event definition. Thus, the evaluation of possible actions
is unlikely to result in further insight beyond the general reliability improvements associated with eliminating
single points of failure.
The SDT discussed and decided to keep the P7 Contingency category because common structure Contingencies are
often evaluated after categories P0 and P1 as the most common minimum level of transmission reliability assessment.
These events have a high likelihood of occurrence due to the following reasons:
•

Historical events that include simultaneous forced outage due to tripping of the double-circuit power lines
due to electrical storm events;

•

Environment-caused factors include pollution buildup, such as dust, that could cause faulted condition that
trips both transmission lines on a common tower;

•

Avian-caused outages that impact both transmission lines on a common tower;

•

Smoke from nearby wildfires can cause simultaneous tripping of both circuits on a common tower;

•

Nearby wildfires can impact System Operation as System Operators proactively de-energize both lines on a
common tower to avoid further impact to the transmission grid in the event of a simultaneous tripping of
both lines that may be carrying high power transfer between areas;

•

Weather-related causes such as lightning, flooding, wind, or icing can cause tripping of both transmission
lines on a common tower;

•

Natural disaster such as winter storm can cause transmission tower to collapse, taking out both lines strung
on the same tower;

•

Other incidents such as vehicle accident, aircraft accident, vandalism, or animal contact can adversely impact
both transmission lines on the common tower.

•

Loss of two circuits running in parallel, simultaneously, is likely to have a greater system impact versus loss
of two unrelated or geographically separated circuits. Therefore, there is greater potential for reliability
concerns, especially during heavy transfers that are likely during periods of extreme weather, due to loss of
both circuits of a double-circuit line.

•

Due to the reasons above, Contingencies that involve double-line circuits on a common tower are mostly
included in the critical multiple Contingency list in System Operations reliability assessment.

Some, but not all, items to consider when developing the rationale for selecting Contingencies are:
•

Past studies,

•

Subject matter expert knowledge of the responsible entity’s System (to be supplemented with data or
analysis), and
NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
10

Requirement 7

•

Historical data from past operating events.

Lastly, regarding the Bulk Electric System (BES) voltage levels for the Contingencies, the SDT reviewed previous major
wide-area benchmark events and found that the Facilities that were out of service by these events have voltages that
are 200 kV and above. Thus, it is the reason for establishing voltages of 200 kV and above for Contingencies in Table
1 of TPL-008-1. The monitoring of potential impact is still applicable to Facilities with all BES voltage levels. However,
with that said, the SDT recognized that many PCs and TPs have Contingencies that include all BES levels. Responsible
entities may elect to use the existing Contingencies that they already have and report the criteria violations for the
categories in TPL-008-1 Table 1.

NERC | Technical Rationale and Justification for TPL-008-1 | July 2024
10

Requirement R8
Requirement R8 was drafted to provide clarity on the following:
1. What planning study cases are required?
The Requirement R8 includes the following number of assessments to complete the Extreme Temperature
Assessment and address FERC Order No. 896 directives per paragraph 111 that “direct NERC to require in
the proposed new or modified Reliability Standard that responsible entities perform both steady state and
transient stability (dynamic) analyses in the extreme heat and cold weather planning studies”. In addition,
Requirement R8 also addresses FERC Order No. 896 directives per paragraph 124 that “require the use of
sensitivity cases to demonstrate the impact of changes to the assumptions used in the benchmark planning
case”. Requirement R8 also addresses FERC Order No. 896 directives per paragraph 124 that sensitivity
cases “should consider including conditions that vary with temperature such as load, generation, and
system transfers.” Since the benchmark planning case(s) already include System conditions under extreme
heat or extreme cold events, the sensitivity analysis is to include changes to at least one of the following
conditions: generation, real and reactive forecasted Load, or transfers. Since the minimum requirement
includes changes to one of these conditions, the PCs and the TPs can include further sensitivity assessments
to change more conditions if they choose to do so.
The following provides the number of assessments required for the benchmark planning and sensitivity
cases to complete the Extreme Temperature Assessment.
Type of Extreme
Temperature
Assessment

Extreme Cold Temperature
Event

Extreme Heat
Temperature Event

Total

Benchmark Planning
Case Analysis

One extreme cold
benchmark planning case
assessment

One extreme heat
benchmark planning case
assessment

Two benchmark
planning case
assessments

Sensitivity Case
Analysis

One sensitivity case with
changes to at least one of
the following conditions:
generation, real and
reactive forecasted Load,
or transfers

One sensitivity case with
changes to at least one of
the following conditions:
generation, real and
reactive forecasted Load,
or transfers

Two sensitivity case
assessments

Total

A total of four
assessments to
complete the
Extreme
Temperature
Assessment

2. What are the types of analyses required?
There are two types of analyses required: steady-state and transient stability. Each type of analysis must be
completed for each of the four cases described in the table above. This requirement is to satisfy FERC Order
No. 896 directive paragraph 111.

NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
19

Requirement R9
FERC Order No. 896 identifies a deficiency in the existing Reliability Standard TPL-001-5.1 where “planning
coordinators and transmission planners are required to evaluate possible actions to reduce the likelihood or mitigate
the consequences of extreme temperature events but are not obligated to develop corrective action plans” (¶139).
Given potential severe consequences of extreme cold and extreme heat events, FERC Order No. 896 raises the bar
and “directs NERC to require in the new or modified Reliability Standard the development of extreme weather
corrective action plans for specified instances when performance standards are not met” (¶152).
Due to higher likelihood of categories P0 and P1, these categories are held to a higher performance requirement in
benchmark planning cases. Corrective Action Plans are required to address performance deficiencies for categories
P0 and P1 in benchmark planning cases analyzed in the Extreme Temperature Assessment.
Furthermore, having a Corrective Action Plan requirement for categories P0 and P1 in benchmark planning cases
ensures resilience during future extreme cold and extreme heat temperature events, when the transmission System
is required to be P1 Contingency-secure (for steady-state and transient stability).
Given that a category P0 represents a continuous System condition without any system disturbances, the SDT
determined that load shedding should not be considered as a Corrective Action Plan. However, the SDT has
determined that load curtailment may be considered for a P1 Contingency as a Corrective Action Plan where load
shed is allowed to prevent system-wide failures and ensuring the continued operation of essential services under a
critical P1 Contingency in the extreme heat and cold temperature events. The SDT also emphasizes that alternative
solutions, other than firm load curtailment, are evaluated in higher priorities. Non-Consequential Load Loss is
permitted as an interim solution in situations that are beyond the control of the Planning Coordinator or Transmission
Planner that prevent the implementation of a Corrective Action Plan in the required timeframe; however, the
responsible entity must document the situation causing the problem, alternatives evaluated, and take actions to
resolve the situation. Future revisions to the Corrective Action Plan are allowed, provided that the planned Bulk
Electric System continues to meet the performance requirements of Table 1.
FERC Order No. 896 also directs NERC “to develop certain processes to facilitate interaction and coordination with
applicable regulatory authorities or governing bodies responsible for retail electric service as appropriate in
implementing a corrective action plan” (¶152). In the event that Non-Consequential Load Loss is included in the
Corrective Action Plan for a P1 Contingency, the responsible entity shall document alternative(s) considered, make
the Corrective Action Plan available to, and solicit feedback from, applicable regulatory authorities or governing
bodies responsible for retail electric service issues.

NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
20

Requirement R10
The requirement for responsible entities to evaluate and document possible actions designed to reduce the likelihood
or mitigate the consequences and adverse impacts when the study results in the benchmark planning cases analyses
conclude there could be instability, uncontrolled separation, or Cascading for P7 Contingencies is in response to
directives outlined in FERC Order No. 896.
P7 Contingencies involve multiple element outages resulting from a single event, making them relatively less likely to
occur, compared to categories P0 and P1, but potentially causing more severe system impacts. Considering both the
likelihood of these Contingencies, and the fact that the Extreme Temperature Assessment already addresses lowprobability System conditions, the SDT determined that Corrective Action Plans should not be required for P7
Contingencies. However, due to the potential severity resulting from single-Contingency multiple element outages,
the SDT believes it is appropriate for responsible entities to at least evaluate and document possible mitigation
actions to reduce the likelihood or mitigate the consequences and adverse impacts of the event(s) when analyses
conclude there could be instability, uncontrolled separation, or Cascading. The biggest benefit from the evaluation
and documentation of the possible mitigating actions is it allows a responsible entity to see where major reliability
concerns exist that may need to be addressed; and, if a sufficiently large number of reliability concerns are identified,
it may encourage transmission upgrade mitigation option(s) to be considered and implemented without it being
strictly called for in the standard. Not requiring Corrective Action Plans for these Contingencies, but requiring the
evaluation, is a compromise from having Corrective Action Plans for all studied Contingencies.
Furthermore, FERC Order No. 896 requires “the use of sensitivity cases to demonstrate the impact of changes to the
assumptions used in the benchmark planning case” (¶124). FERC Order No. 896 also states: “NERC should determine
whether corrective action plans should be required for single or multiple sensitivity cases, and whether corrective
action plans should be developed if a contingency event that is not already included in benchmark planning case
would result in cascading outages, uncontrolled separation, or instability” (¶158). The SDT acknowledges that
sensitivity analysis is an important component of a robust transmission planning study. A requirement to develop
and implement Corrective Action Plans for sensitivity cases may incentivize responsible entities to select fewer or
less severe sensitivities. An incentive to select fewer sensitivities is undesirable because sensitivity study results are
used to identify constraints and initiate deeper analysis into the variables that impact those constraints. The study
results of sensitivity cases are also important to inform the development of Corrective Action Plans in the benchmark
planning cases. Therefore, the SDT determined the responsible entity must evaluate and document possible actions
designed to reduce the likelihood or mitigate the consequences and adverse impacts of the event(s) when analyses
of sensitivity cases conclude there could be instability, uncontrolled separation, or Cascading for categories P0, P1,
and P7. Finally, TPL-008-1 does not preclude the responsible entity from developing Corrective Action Plans for
sensitivity cases beyond what is required in the standard.

NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
21

Requirement R11
The requirement for responsible entities to share Extreme Temperature Assessment results aligns with directives in
FERC Order No. 896, emphasizing coordination and sharing of study findings. It ensures collaboration among
stakeholders and timely dissemination of critical information to entities with reliability-related needs. This fosters a
collective understanding of reliability concerns identified in wide-area studies, thereby enhancing overall grid
reliability.

NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
22

Attachment 1: Extreme Temperature Assessment Zones
The map depicts an approximation of the zones to be used in the Extreme Temperature Assessment and is provided
as a visual aid for each Planning Coordinator to identify the zone(s) to which the Planning Coordinator belongs to
under Attachment 1. The zone topology is a function of balancing authority jurisdiction and general knowledge of
zonal weather patterns. The goal of the topology was to split the North American System into several distinct zones
that have similar electric power system properties (i.e., balancing authority and interconnections) and similar
weather or climatological patterns. Balancing authorities with large areas of jurisdiction, exclusively ISOs and RTOs,
are assigned their own weather zone. In geographical areas comprised of multiple balancing authorities, generalized
weather zones are created to best represent zonal weather patterns.
The NPCC region of the Eastern Interconnection was divided into New England, New York, Quebec Interconnection,
Ontario, and Maritimes. The Planning Coordinators for the NPCC region of the Eastern Interconnection are listed
below:
•

New England: Planning Coordinators in NPCC that primarily serve the six New England States.

•

New York: Planning Coordinators in NPCC that primarily serve New York.

•

Quebec: Planning Coordinators that primarily serve Quebec in the NPCC Region.

•

Ontario: Planning Coordinators in NPCC that primarily serve Ontario.

•

Maritimes: Planning Coordinators in NPCC that primarily serve New Brunswick, Nova Scotia, Prince Edward
Island, and the Northern Maine Independent System Administrator (NMISA). The NMISA is responsible for
the administration of the northern Maine transmission system and electric power markets in Aroostook and
Washington counties, with the load served radially from New Brunswick. It was not included in the New
England division since there are no physical ties between NMISA and ISO-NE which is the Planning
Coordinator serving the remainder of the six New England States.

Additionally, SERC combined NERC Assessment areas of SERC-East, SERC-Central, and SERC-Southeast into a single
zone based on climate similarities. Northwest Regions, WECC-SW, SERC, and SERC-FP were based on balancing
authority PNNL data. SPP-N, SPP-S, MISO-N, and MISO-S were aggregated based on county-level PNNL data.

NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
22

Unofficial Comment Form – Draft 4

Project 2023-07 Transmission Planning Performance Requirements for
Extreme Weather
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on draft four of TPL-008-1 – Transmission System Planning Performance
Requirements for Extreme Temperature Events by 8 p.m. Eastern, November 21, 2024.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Senior Standards
Developer, Jordan Mallory (via email), or at 470-479-7538.
Background Information

On June 15, 2023, FERC issued FERC Order No. 896 that acknowledges the “challenges associated with
planning for extreme heat and cold weather events, particularly those that occur during periods when the
Bulk-Power System must meet unexpectedly high demand. Extreme heat and cold weather events have
occurred with greater frequency in recent years and are projected to occur with even greater frequency in
the future. These events have shown that load shed during extreme temperature result in unacceptable
risk to life and have extreme economic impact. As such, the impact of concurrent failures of Bulk-Power
System generation and transmission equipment and the potential for cascading outages that may be
caused by extreme heat and cold weather events should be studied and corrective actions should be
identified and implemented.” 1
Therefore, the Commission directed, in FERC Order No. 896, to develop a new or modified Reliability
Standard to address a lack of long-term planning requirement(s) for extreme heat and cold weather
events. Specifically, FERC directed NERC to develop modifications to Reliability Standard TPL-001-5.1 or a
new Reliability Standard, to require the following: (1) development of benchmark planning cases based on
major prior extreme heat and cold weather events and/or meteorological projections; (2) planning for
extreme heat and cold weather events using steady state and transient stability analyses expanded to
cover a range of extreme weather scenarios including the expected resource mix's availability during
extreme heat and cold weather conditions, and including the wide-area impacts of extreme heat and cold
weather; and (3) development of corrective action plans that mitigate any instances where performance
requirements for extreme heat and cold weather events are not met.

1

N. Am. Elec. Reliability Corp., 183 FERC ¶ 61,191 (2023) (FERC Order), Final Rule. eLibrary | File List (ferc.gov)

RELIABILITY | RESILIENCE | SECURITY

Questions

1. The Drafting Team (DT) updated Requirement R2 based on comments received. Do you agree? If
you do not agree, please provide your recommendation and, if appropriate, technical or
procedural justification.
Yes
No
Comments:
2. The DT updated Requirement R9 based on comments received. Do you agree? If you do not agree,
please provide your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
3. The DT updated Attachment 1 based on comments received. Do you agree? If you do not agree,
please provide your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
4. The DT believes proposed modifications in TPL-008-1 provide entities with flexibility to meet the
reliability objectives in a cost-effective manner. Do you agree? If you do not agree, or if you agree
but have suggestions for improvement to enable more cost-effective approaches, please provide
your recommendation and, if appropriate, technical or procedural justification.
Yes
No
Comments:
5. Provide any additional comments for the drafting team to consider, including the provided
technical rationale document, if desired.
Comments:

Unofficial Comment Form
Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather | November 2024

Violation Risk Factor and Violation Severity Level
Justifications

Project 2023-07 Transmission System Planning Performance Requirements for
Extreme Weather
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 2023-07 Transmission System Planning Performance Requirements for Extreme Weather. 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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

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
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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

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 Justifications for TPL-008-1, Requirement R1
Proposed VRF

Lower

NERC VRF Discussion

A VRF of Lower is appropriate due to the fact that the Planning Coordinators, in conjunction with its
Transmission Planner(s) will determine joint responsibilities for requirements throughout TPL-008-1.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

5

VSLs for TPL-008-1, Requirement R1
Lower

Moderate

High

Severe

The responsible entity completed
its individual and joint
responsibilities such that the
Extreme Temperature Assessment
was completed, but it was
completed less than or equal to six
months late.

The responsible entity completed
its individual and joint
responsibilities such that the
Extreme Temperature Assessment
was completed, but it was
completed more than six months
but less than or equal to 12 months
late.

The responsible entity completed
its individual and joint
responsibilities such that the
Extreme Temperature Assessment
was completed, but it was
completed more than 12 months
but less than or equal to 18 months
late.

The Planning Coordinator, in
conjunction with its Transmission
Planner(s), failed to identify
individual and joint responsibilities
for completing the Extreme
Temperature Assessment.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

OR
The responsible entity completed
its individual and joint
responsibilities such that the
Extreme Temperature Assessment
was completed, but it was
completed more than 18 months
late.

6

VSL Justifications for TPL-008-1, Requirement R1
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the Planning Coordinator and Transmission Planner to determine
who completes the responsibilities throughout TPL-008-1. The responsibilities documentation will either be
developed or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

7

VRF Justifications for TPL-008-1, Requirement R2
Proposed VRF

High

NERC VRF Discussion

A VRF of high is appropriate due to the fact that selecting a benchmark event to perform an extreme
temperature assessment can affect the grid based on planning analysis for future events.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

8

VSLs for TPL-008-1, Requirement R2
Lower
N/A

Moderate
N/A

High

Severe

The Planning Coordinator
coordinated with all Planning
Coordinators within each identified
zone to identify one common
extreme heat and one common
extreme cold benchmark
temperature event for completing
the Extreme Temperature
Assessment, but one of the
identified events failed to meet all
the criteria of Requirement R2.

The Planning Coordinator
coordinated with all Planning
Coordinators within each identified
zone to identify one common
extreme heat and one common
extreme cold benchmark
temperature event for completing
the Extreme Temperature
Assessment, but both of the
identified events failed to meet all
of the criteria of Requirement R2.
OR
The Planning Coordinator failed to
coordinate with all Planning
Coordinators within each identified
zone to identify one common
extreme heat and one common
extreme cold benchmark
temperature event for completing
the Extreme Temperature
Assessment.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

9

VSL Justifications for TPL-008-1, Requirement R2
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

This VSL has been assigned as a binary due to the benchmark event needing to be selected for benchmark
planning cases to be completed. You either select a benchmark event or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

10

VRF Justifications for TPL-008-1, Requirement R3
Proposed VRF

Medium

NERC VRF Discussion

A VRF of medium is appropriate due to the fact that it is important to develop and maintain System models
within an entity’s planning area for performing Extreme Temperature Assessments. Connecting to MOD-032 to
provide important data needed to assist entities with System models is also important for accurate information
to be used.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

11

VSLs for TPL-008-1, Requirement R3
Lower
N/A

Moderate
N/A

High
N/A

Severe
The Planning Coordinator did not
coordinate with all Planning
Coordinators within each of its
identified zone(s) to implement a
process for developing benchmark
planning cases.
OR
The Planning Coordinator
coordinated with all Planning
Coordinators within each of its
identified zone(s) to implement a
process for developing benchmark
planning cases, but the process did
not include all of the required
elements.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

12

VSL Justifications for TPL-008-1, Requirement R3
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either develops and maintains the System
models within its planning area or it does not develop and maintain the System models within its planning area.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

13

VRF Justifications for TPL-008-1, Requirement R4
Proposed VRF

High

NERC VRF Discussion

The VRF of High is appropriate because it could directly affect the electrical state or capability of the BPS if
coordination is not completed for benchmark planning cases and sensitivity cases for the Extreme Temperature
Assessment results.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

14

VSLs for TPL-008-1, Requirement R4
Lower
N/A

Moderate
N/A

High
N/A

Severe
The responsible entity, as identified
in Requirement R1, did not use the
coordination process to develop
benchmark planning cases or
sensitivity cases.
OR
The responsible entity, as identified
in Requirement R1, used the
coordination process to develop
benchmark planning cases and
sensitivity cases, but did not use
data consistent with that provided
in accordance with the MOD-032
standard, supplemented by other
sources as needed, for one or more
of the required cases.
OR
The responsible entity, as identified
in Requirement R1, used the
coordination process and data
consistent with that provided in
accordance with the MOD-032
standard, supplemented as
needed, but failed to develop one
or more of the required planning or
sensitivity cases.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

15

VSL Justifications for TPL-008-1, Requirement R4
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the Planning Coordinator to develop and implement a process for
coordinating the development of benchmark planning cases. The benchmark planning cases will either be
developed and implemented or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

16

VRF Justifications for TPL-008-1, Requirement R5
Proposed VRF

Medium

NERC VRF Discussion

A VRF of medium is appropriate due to the importance of having criteria for acceptable System steady state
voltage limits of post-Contingency voltage deviations for performing Extreme Temperature Assessments.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

17

VSLs for TPL-008-1, Requirement R5
Lower
N/A

Moderate
N/A

High
N/A

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

Severe
The responsible entity, as identified
in Requirement R1, did not have
criteria for acceptable System
steady state voltage limits and
post-Contingency voltage
deviations for completing the
Extreme Temperature Assessment.

18

VSL Justifications for TPL-008-1, Requirement R5
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either having acceptable criteria for System
steady state voltage limits and post-contingency voltage deviations or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

19

VRF Justifications for TPL-008-1, Requirement R6
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate due to the importance of defining and documenting the criteria or methodology for
System instability, uncontrolled separation, or Cascading.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

20

VSLs for TPL-008-1, Requirement R6
Lower
N/A

Moderate
N/A

High
N/A

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

Severe
The responsible entity, as identified
in Requirement R1, failed to define
or document the criteria or
methodology to be used in the
Extreme Temperature Assessment
to identify instability, uncontrolled
separation, or Cascading within an
Interconnection.

21

VSL Justifications for TPL-008-1, Requirement R6
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

22

VRF Justifications for TPL-008-1, Requirement R7
Proposed VRF

Medium

NERC VRF Discussion

A VRF of medium is appropriate for this requirement. Identifying Contingencies for performing Extreme
Temperature Assessments for each of the event categories in Table 1 can indirectly impact the BES.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

23

VSLs for TPL-008-1, Requirement R7
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity, as identified
in Requirement R1, identified
Contingencies for each category in
Table 1 that are expected to
produce more severe System
impacts on its portion of the Bulk
Electric System, but did not include
the rationale for those
Contingencies selected for
evaluation as supporting
information.

The responsible entity, as identified
in Requirement R1, did not identify
Contingencies for each category in
Table 1 that are expected to
produce more severe System
impacts on its portion of the Bulk
Electric System.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

24

VSL Justifications for TPL-008-1, Requirement R7
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

25

VRF Justifications for TPL-008-1, Requirement R8
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate due to the importance of performing an Extreme Temperature Assessment every 5
years.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

26

VSLs for TPL-008-1, Requirement R8
Lower

Moderate

High

Severe

The responsible entity, as identified
in Requirement R1, completed
steady state and transient stability
analyses in the Extreme
Temperature Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for one
or more sensitivity cases in
accordance with Requirement R8.

The responsible entity, as identified
in Requirement R1, completed
steady state and transient stability
analyses in the Extreme
Temperature Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for one
or more benchmark planning cases
in accordance with Requirement
R8.

The responsible entity, as identified
in Requirement R1, completed
steady state and transient stability
analyses in the Extreme
Temperature Assessment using the
Contingencies identified in
Requirement R7, but failed to
evaluate and document results for
one or more of the sensitivity cases
in accordance with Requirement
R8.

The responsible entity, as identified
in Requirement R1, completed
steady state and transient stability
analyses in the Extreme
Temperature Assessment using the
Contingencies identified in
Requirement R7, but failed to
evaluate and document results for
one or more of the benchmark
planning cases in accordance with
Requirement R8.
OR
The responsible entity, as identified
in Requirement R1, failed to
complete steady state or transient
stability analyses and document
results in the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, in accordance
with Requirement R8.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

27

VSL Justifications for TPL-008-1, Requirement R8
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

28

VRF Justifications for TPL-008-1, Requirement R9
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate for this requirement. Developing a Corrective Action Plan is important to the BES as
it assists entities when Systems are unable to meet performance requirements.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

29

VSLs for TPL-008-1, Requirement R9
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity, as identified
in Requirement R1, developed a
Corrective Action Plan in
accordance with Requirement R9,
but failed to make its Corrective
Action Plan available to, or solicit
feedback from, applicable
regulatory authorities or governing
bodies responsible for retail
electric service issues.

The responsible entity, as identified
in Requirement R1, failed to
develop a Corrective Action Plan
when the benchmark planning case
study results indicate the System is
unable to meet performance
requirements for the Table 1 P0 or
P1 Contingencies.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

OR
The responsible entity, as identified
in Requirement R1, developed a
Corrective Action Plan, but it was
missing one or more of the
elements of Requirement R9 Part
9.1, 9.3 and 9.4 (as applicable).

30

VSL Justifications for TPL-008-1, Requirement R9
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either having acceptable criteria for System
steady state voltage limits and post-contingency voltage deviations or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

31

VRF Justifications for TPL-008-1, Requirement R10
Proposed VRF

Lower

NERC VRF Discussion

A VRF of lower has been assigned to Requirement R10. Documenting possible actions to reduce the likelihood
or mitigate the consequences and adverse impacts are administrative in nature.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

32

VSLs for TPL-008-1, Requirement R10
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity, as identified
in Requirement R1, evaluated and
documented possible actions to
reduce the likelihood or mitigate
the consequences and adverse
impacts of the event(s) when
analyses conclude there could be
instability, uncontrolled separation,
or Cascading within an
Interconnection where required
under Requirement R10 Part 10.1,
but failed to evaluate and
document possible actions where
required under Requirement R10
Part 10.2.

The responsible entity, as identified
in Requirement R1, evaluated and
documented possible actions to
reduce the likelihood or mitigate
the consequences and adverse
impacts of the event(s) when
analyses conclude there could be
instability, uncontrolled separation,
or Cascading within an
Interconnection where required
under Requirement R10 Part 10.2,
but failed to evaluate and
document possible actions where
required under Requirement R10
Part 10.1.
OR
The responsible entity, as identified
in Requirement R1, failed to
evaluate and document possible
actions to reduce the likelihood or
mitigate the consequences and
adverse impacts of the event(s)
when analyses conclude there
could be instability, uncontrolled
separation, or Cascading within an
Interconnection where required
under Requirement R10 Parts 10.1
and 10.2.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

33

VSL Justifications for TPL-008-1, Requirement R10
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the fact that the responsible entity will have evaluated and
documented possible actions to mitigate adverse impacts.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

34

VRF Justifications for TPL-008-1, Requirement R11
Proposed VRF

Medium

NERC VRF Discussion

The VRF of Medium is appropriate because it could directly affect the electrical state or capability of the BES if
entities are not aware of the results from its Extreme Temperature Assessment results.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

35

VSLs for TPL-008-1, Requirement R11
Lower

Moderate

High

Severe

The responsible entity, as identified
in Requirement R1, provided its
Extreme Temperature Assessment
results to functional entities having
a reliability related need who
requested the information in
writing, but it was more than 60
days but less than or equal to 80
days following the request.

The responsible entity, as identified
in Requirement R1, provided its
Extreme Temperature Assessment
results to functional entities having
a reliability related need who
requested the information in
writing, but it was more than 80
days but less than or equal to 100
days following the request.

The responsible entity, as identified
in Requirement R1, provided its
Extreme Temperature Assessment
results to functional entities having
a reliability related need who
requested the information in
writing, but it was more than 100
days but less than or equal to 120
days following the request.

The responsible entity, as identified
in Requirement R1, provided its
Extreme Temperature Assessment
results to functional entities having
a reliability related need who
requested the information in
writing, but it was more than 120
days following the request.
OR
The responsible entity, as identified
in Requirement R1, did not provide
its Extreme Temperature
Assessment results to functional
entities having a reliability related
need who submitted a written
request for the information.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

36

VSL Justifications for TPL-008-1, Requirement R11
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | November 2024

37

Consideration of FERC Order 896 Directives

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
November 2024
On June 15, 2023, FERC issued a Final Rule, Order No. 896, directing NERC to develop a new or modified Reliability Standard to address a lack
of a long-term planning requirement(s) for extreme heat and cold weather events. Specifically, FERC directed NERC to develop modifications to
Reliability Standard TPL-001-5.1 or to develop a new Reliability Standard to require the following: (1) development of benchmark planning
cases based on major prior extreme heat and cold weather events and/or meteorological projections; (2) planning for extreme heat and cold
weather events using steady state and transient stability analyses expanded to cover a range of extreme weather scenarios including the
expected resource mix's availability during extreme heat and cold weather conditions, and including the wide-area impacts of extreme heat
and cold weather; and (3) development of corrective action plans that mitigate any instances where performance requirements for extreme
heat and cold weather events are not met. FERC directed NERC to submit a new or revised standard within 18 months, or by December 2024.
The below provides the directives from FERC Order 896 along with the drafting team’s consideration of the directives.

Directive Language

FERC Order 896 Directives

P35. “[W]e direct NERC to: (1) develop extreme heat and cold weather
benchmark events, and (2) require the development of benchmark
planning cases based on identified benchmark events.”
P36: “…As recommended by commenters, NERC should consider the
examples of approaches for defining benchmark events identified in the
NOPR (e.g., the use of projected frequency or probability distribution).
NERC may also consider other approaches that achieve the objectives
outlined in this final rule.”

Consideration of Directives

The ERO has worked with respective subject matter experts, including
climate experts, the six regions, etc., to explore extreme heat and extreme
cold benchmark temperature events. NERC, in consultation with climate
data subject matter expert consultants on the benchmark events, utilized
publicly available modeled data to address the requirements of TPL-008-1
that define extreme heat and extreme cold benchmark temperature
events.
Specifically, based on the available data, the drafting team determined that
extreme benchmark temperature events must: 1) consider no less than
forty years of historical temperature data, 2) include recent temperature

RELIABILITY | RESILIENCE | SECURITY

Directive Language

FERC Order 896 Directives

Consideration of Directives

data due to ongoing climate changes, and 3) represent one of the twenty
worst extreme temperature conditions over the forty year period, based on
a 3-day rolling average of daily maximum (heat) or minimum (cold)
temperatures.
The ERO will maintain a library of benchmark temperature events that
meet these requirements. Responsible entities will be able to review and
select benchmark temperature events from this library to assist with the
development of benchmark planning cases. However, responsible entities
may also identify benchmark temperature events via their own processes,
provided that the event meets the criteria of Requirement R2 and is agreed
upon by all PCs within the zone.
Should the extreme heat and cold weather benchmark events provided not
suffice for the entities zone, the Planning Coordinator (PC) in coordination
with all PCs within its zone, may develop a common extreme heat and
extreme cold weather benchmark event to use for the TPL-008-1 Standard.
The drafting team developed requirements within TPL-008-1 to require PCs
within zones to select one common extreme heat benchmark temperature
event and one common extreme cold benchmark temperature event
(Requirement R2). After selecting its benchmark events, the responsible
entity is required to implement a process for coordinating the development
of benchmark planning cases and sensitivity cases among the responsible
entities (Requirement R3) and to develop benchmark planning cases and
sensitivity cases (Requirement R4).

Consideration of FERC Order 896 Directives
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | November 2024

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Directive Language

FERC Order 896 Directives

P37. “Because the impact of most extreme heat and cold events spans
beyond the footprints of individual planning entities, it is important that all
responsible entities likely to be impacted by the same extreme weather
events use consistent benchmark events. Doing so is important to ensuring
that neighboring planning regions are assuming similar weather conditions
and are able to coordinate their assumptions accordingly. As a result,
defining the benchmark event in a manner that provides responsible
entities significant discretion to determine the applicable meteorological
conditions would not meet the objectives of this final rule.”
P38. “[I]n developing extreme heat and cold benchmark events, NERC shall
ensure that benchmark events reflect regional differences in climate and
weather patterns.”

Consideration of Directives

NERC, in consultation with climate data subject matter expert consultants
on benchmark events, developed subregions or “zones” of North America
that are likely to experience similar weather conditions. These zones also
consider practical concerns with coordination such as the boundaries of
Interconnections and Balancing Authority Areas.
The drafting team developed Requirement R2 such that PCs within the
same zone are required to select one common extreme heat benchmark
temperature event and one common extreme cold benchmark
temperature event. This process balances the opportunity to provide input
with the need for common events to be modeled over wide areas.
NERC, in consultation with climate data subject matter expert consultants
on benchmark events, has utilized publicly available modeled data in the
last forty-three years (1980-2022), as well as more than eighty years of
projected hourly meteorology data from PNNL to ensure regional
differences in climate and weather patterns are reflected in the zones
depicted in Attachment 1 of TPL-008-1.
A Map has been added to the TPL-008-1 Standard showing the zones split
throughout the US and Canada. These are to be considered wide area, and
regional differences went into consideration when developing the data
based on extreme historical events over the past 40 years.

P39. “We also direct NERC to include in the Reliability Standard the
framework and criteria that responsible entities shall use to develop from
the relevant benchmark event planning cases to represent potential
weather-related contingencies (e.g., concurrent/correlated generation and
transmission outages, derates) and expected future conditions of the
system such as changes in load, transfers, and generation resource mix,
and impacts on generators sensitive to extreme heat or cold, due to the
weather conditions indicated in the benchmark events. Developing such a

The directive is addressed in Requirements R3 and R4 of the proposed TPL008-1 standard.
Requirement R3 obligates the PC to implement a process to coordinate the
development of the benchmark planning cases and sensitivity cases. This
process shall include: 1) the selection of System models within the LongTerm Transmission Planning Horizon to serve as a starting point for the
benchmark planning cases, 2) forecasted seasonal and temperature

Consideration of FERC Order 896 Directives
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | November 2024

3

Directive Language

FERC Order 896 Directives

framework would provide a common design basis for responsible entities
to follow when creating benchmark planning cases. This would not only
help establish a clear set of expectations for responsible entities to follow
when developing benchmark planning events, but also facilitate auditing
and enforcement of the Standard.”

P40. “We also direct NERC to ensure the reliability standard contains
appropriate mechanisms for ensuring the benchmark event reflects up-todate meteorological data.”

P50. “[W]e…direct NERC to require that transmission planning studies
under the new or revised Reliability Standard consider the wide-area
impacts of extreme heat and cold weather. We direct NERC to clearly
describe the process that an entity must use to define the wide-area
boundaries. While commenters provide various views in favor of both a
geographical approach and electrical approach to defining wide-area
boundaries, we do not adopt any one approach in this final rule…NERC
should consider the comments in this proceeding when developing a new
or modified reliability standard that considers the broad area impacts of
extreme heat and cold weather.”

Consideration of Directives

dependent adjustments for Load, generation, Transmission, and transfers
within the zone to represent the selected benchmark temperature events,
3) assumed seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers outside of the zone as needed, and
4) the identification of changes to at least one of generation, real and
reactive forecasted load, or transfers to serve as a sensitivity case.
Requirement R4 obligates the responsible entity to develop benchmark
planning cases and sensitivity cases for performing the Extreme
Temperature Assessment which reflects System conditions from the
selected benchmark events. Requirement R4 also references the NERC
MOD-032 Reliability Standard that provides PCs and Transmission Planners
a mechanism for obtaining the data needed to develop the benchmark
planning cases.
Requirement R2 Part 2.1 requires that the temperature data collected to
identify benchmark temperature events includes 40 years of data “ending
no more than 5 years prior to the time the benchmark temperature events
are selected”. This requirement ensures that the window of time
considered for benchmark temperature events reflects up-to-date data.
The up-to five-year gap was included due to potential lags in data sources.
To understand the complexities of defining wide-area boundaries, the
drafting team reviewed the extreme weather events mentioned within
FERC Order No. 896, as well as the comments received during the FERC
Order proceeding. In addition, NERC consulted with climate data subject
matter experts who evaluated publicly available modeled data in the last
forty-three years (1980-2022) and more than eighty years of projected
hourly meteorology data from PNNL.
The drafting team struck a balance between a geographical approach and
an electrical approach by dividing North America into zones that are likely
to experience similar weather conditions but also consider practical

Consideration of FERC Order 896 Directives
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | November 2024

4

Directive Language

FERC Order 896 Directives

P58. “[W]e…direct NERC to develop benchmark events for extreme heat
and cold weather events through the Reliability Standards development
process. We agree … that the development of adequate benchmark events
is critical and should be committed to the subject matter experts on the
standards drafting team. ”

Consideration of Directives

concerns with coordination such as the boundaries of Interconnections and
Balancing Authority Areas. These zones are depicted in Attachment 1 of
TPL-008-1, and PCs will be required to coordinate with all PCs in the zone(s)
they belong to.
The drafting team considered various approaches to developing benchmark
temperature events. With assistance from NERC’s subject matter expert
consultants, the drafting team identified the key components of
temperature events that are necessary for the event to constitute an
adequate benchmark temperature event. These components were
included in Requirement R2.
Specifically, based on the available data, the drafting team determined that
extreme benchmark temperature events must: 1) consider no less than
forty years of historical temperature data, 2) include recent temperature
data due to ongoing climate changes, and 3) represent one of the twenty
worst extreme temperature conditions over the forty year period based on
a 3-day rolling average of daily maximum (heat) or minimum (cold)
temperatures.
The ERO will maintain a library of benchmark temperature events that
meet these requirements. Responsible entities will be able to review and
select benchmark temperature events from this library to assist with the
development of benchmark planning cases. However, responsible entities
may also identify benchmark temperature events via their own processes
provided that the event meets the criteria of Requirement R2 and is agreed
upon by all PCs within the zone.
In addition to describing the minimum requirements of a benchmark
temperature event, Requirement R2 obligates PCs within the same zone to
coordinate in selecting one common extreme heat benchmark
temperature event and one common extreme cold benchmark

Consideration of FERC Order 896 Directives
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | November 2024

5

Directive Language

FERC Order 896 Directives

P60. “[W]e…direct NERC to designate the type(s) of entities responsible for
developing benchmark planning cases and conducting wide-area studies
under the new or modified Reliability Standard…benchmark planning cases
should be developed by registered entities such as large planning
coordinators, or groups of planning coordinators, with the capability of
planning on a regional scope.”
P61: “We believe the designated responsible entities should have certain
characteristics, including having a wide-area view of the Bulk-Power
System and the ability to conduct long-term planning studies across a wide
geographic area. The responsible entities should also have the planning
tools, expertise, processes, and procedures to develop benchmark planning
cases and analyze extreme weather events in the long-term planning
horizon.”
P62: “To comply with this directive, NERC may designate the tasks of
developing benchmark planning cases and conducting wide-area studies to
an existing functional entity or a group of functional entities (e.g., a group
of planning coordinators). NERC may also establish a new functional entity
registration to undertake these tasks. In the petition accompanying the
proposed Reliability Standard NERC should explain how the applicable
registered entity or entities meet the objectives outlined above.”

Consideration of Directives

temperature event for completing the Extreme Temperature Assessment.
This coordination is required to ensure the benchmark temperature event
is reflected over a wide-area.
The drafting team discussed that the Transmission Planner (TP) and/or
Planning Coordinator (PC) would be the responsible entities to address TPL008-1 Requirements. Requirement R1 obligates both the TP and PC to
identify their individual and joint responsibilities.
Requirement R3 obligates each PC to implement a process for coordinating
the development of benchmark planning cases and sensitivity cases, using
the selected benchmark temperature events identified in Requirement R2.
This process must be implemented in coordination with all PCs within the
same zone.
Requirement R4 obligates each responsible entity, as identified in
Requirement R1, to use the coordination process developed in accordance
with Requirement R3 and data consistent with that provided in accordance
with the MOD-032 standard, supplemented by other sources as needed, to
develop benchmark planning cases and sensitivity cases.
The identification of joint and individual responsibilities in Requirement R1
provides a measure of flexibility for PCs and TPs to agree on a distribution
of responsibilities. Thus, while PCs are responsible for implementing the
case development process in Requirement R3, TPs may be responsible for
providing data and completing the case development according to that
process.
The development of benchmark planning cases and sensitivity cases will
require cooperation amongst many PCs and TPs. By requiring participation
from all entities within a zone, TPL-008-1 ensures that the group of
functional entities have a sufficient wide-area view of the Bulk Power

Consideration of FERC Order 896 Directives
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Directive Language

FERC Order 896 Directives

P72. “[W]e direct NERC to require functional entities to share with the
entities responsible for developing benchmark planning cases and
conducting wide-area studies the system information necessary to develop
benchmark planning cases and conduct wide-area studies. Further,
responsible entities must share the study results with affected transmission
operators, transmission owners, generator owners, and other functional
entities with a reliability need for the studies.”

Consideration of Directives

System and the planning tools, expertise, processes and procedures
necessary for developing benchmark planning cases and sensitivity cases.
The directive is addressed in proposed TPL-008-1 in Requirements R3, R4
and R11.
Requirement R3 obligates each PC to implement a process for coordinating
the development of benchmark planning cases, using the selected
benchmark temperature events identified in Requirement R2, among all
Planning Coordinators within a zone.
Requirement R4 obligates each responsible entity, as identified in
Requirement R1, to use the coordination process implemented in
accordance with Requirement R3 and data consistent with that provided in
accordance with the MOD-032 standard, supplemented by other sources as
needed, to develop benchmark planning cases and sensitivity cases.

P73. “Because in this final rule we direct NERC to determine the
responsible entities that will be developing benchmark planning cases and
conducting wide-area studies, it is possible that the selected responsible
entities under the new or modified Reliability Standard will not be able to
request and receive needed data pursuant to MOD-032-1, absent
modification to that Standard.”

Requirement R11 obligates each responsible entity, as identified in
Requirement R1, to provide its Extreme Temperature Assessment results
within 60 calendar days of a request to any functional entity that has a
reliability related need and submits a written request for the information.
The drafting team discussed and determined that data needed to address
the Extreme Temperature Assessment would still be appropriate to receive
through MOD-032. MOD-032 ensures an adequate means of data
collection for transmission planning and requires applicable registered
entities to provide steady-state, dynamic, and short circuit modeling data
to their Transmission Planner(s) and Planning Coordinator(s). As outlined in
Requirement R1 and Attachment 1 of MOD-032, MOD-032 allows various
data collection such as in-service status and capability associated with
demand, generation, and transmission associated with various case types,
scenarios, system operating states, or conditions for the long-term
planning horizon. MOD-032 also requires applicable registered entities to

Consideration of FERC Order 896 Directives
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Directive Language

FERC Order 896 Directives

P76: “[W]e…direct NERC to address the requirement for wide-area
coordination through the standards development process, giving due
consideration to relevant factors identified by commenters in this
proceeding.”
P77. “[W]e direct NERC to require in the new or modified Reliability
Standard that responsible entities share the results of their wide-area
studies with other registered entities such as transmission operators,
transmission owners, and generator owners that have a reliability related
need for the studies.”
P88. “[W]e direct NERC to require under the new or revised Reliability
Standard the study of concurrent/correlated generator and transmission
outages due to extreme heat and cold events in benchmark events as
described in more detail below.”
P92. “These contingencies (i.e., correlated/concurrent, temperature
sensitive outages, and derates) shall be identified based on similar
contingencies that occurred in recent extreme weather events or expected
to occur in future forecasted events.”
P111. “[W]e direct NERC to require in the proposed new or modified
Reliability Standard that responsible entities perform both steady state and

Consideration of Directives

provide “other information requested by the Planning Coordinator or
Transmission Planner necessary for modeling purposes” for each of the
three types of data required. Because the drafting team determined the
responsible entities that will be developing benchmark planning cases are
limited to Planning Coordinators and Transmission Planners, they will be
able to request and receive needed data pursuant to MOD-032. Thus, the
drafting team believes that there is no need to update MOD-032.
The drafting team reviewed all the extreme weather events mentioned
within the FERC Order 896. For this project, the drafting team focused the
scope of Requirement R3 to require each PC to implement a process for
coordinating the development of benchmark planning cases and sensitivity
cases, using the selected benchmark temperature events identified in
Requirement R2, among all PCs within a zone.
This directive is addressed in proposed TPL-008-1 Requirement R11.
Requirement R11 obligates each responsible entity to provide the widearea study results within 60 calendar days of a request to any functional
entity that has a reliability related need and has submitted a written
request for the information.
This directive is addressed in proposed TPL-008-1 through Requirements R3
and R4. Per Requirement R3 Part 3.2, the benchmark planning case
development process must include forecasted seasonal and temperature
dependent adjustments for Load, generation, Transmission, and transfers
within the zone. Per Requirement R4, the data necessary to build the
benchmark planning cases must be provided via MOD-032, supplemented
by other sources as needed. Any concurrent/correlated generator and
transmission outages due to extreme heat and cold events in benchmark
temperature events should be reflected in the model data and thus
represented in the initial conditions of the benchmark planning cases.
This directive is addressed in proposed TPL-008-1 through Requirement R8
and Table 1.

Consideration of FERC Order 896 Directives
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | November 2024

8

Directive Language

FERC Order 896 Directives

transient stability (dynamic) analyses in the extreme heat and cold weather
planning studies. In a steady state analysis, the system components are
modeled as either in-service or out-of-service and the result is a single
point-in-time snapshot of the system in a state of operating equilibrium. A
transient stability (dynamic) analysis examines the system from the start to
the end of a disturbance to determine if the system regains a state of
operating equilibrium. Performing both analyses ensures that the system
has been thoroughly assessed for instability, uncontrolled separation, and
cascading failures in both the steady state and the transient stability
realms.” (internal citations omitted).
P112. “[W]e direct NERC to define a set of contingencies that responsible
entities will be required to consider when conducting wide-area studies of
extreme heat and cold weather events under the new or modified
Reliability Standard. We believe that it is necessary to establish a set of
common contingencies for all responsible entities to analyze. Required
contingencies, such as those listed in Table 1 of Reliability Standard TPL001-5.1 (i.e., category P1 through P7), establish common planning events
that set the starting point for transmission system planning assessments.
Requiring the study of predefined contingencies will ensure a level of
uniformity across planning regions—a feature that will be necessary in the
new or revised Reliability Standard considering that extreme heat and cold
weather events often exceed the geographic boundaries of most existing
planning footprints.”
P113: “[T]he contingencies required in the new or revised Reliability
Standards should reflect the complexities of transmission system planning
studies for extreme heat and cold weather events.”
P116. “[W]e direct NERC to require in the new or modified Reliability
Standard that responsible entities model demand load response in their
extreme weather event planning area. As indicated by several
commenters, because demand load response is generally a mitigating

Consideration of Directives

Requirement R8 requires the responsible entity to complete both steady
state and transient stability analyses and document the assumptions and
results.
Table 1 obligates each responsible entity to perform both steady state and
transient stability analyses and compare the study results against steady
state and stability performance requirements.
This directive is addressed in proposed TPL-008-1 through Requirement R7
and Table 1.
Requirement R7 requires the responsible entity to identify Contingencies
for completing the Extreme Temperature Assessment. The rationale, for
those Contingencies selected for evaluation, shall be available as
supporting information.
The Contingencies for each category in Table 1 of TPL-008-1 correspond to
the well-established Contingencies defined in Reliability Standard TPL-0015.1. Utilizing these well-established Contingencies will ensure a level of
uniformity across planning regions.

TPL-008-1 Requirement R4 meets this directive by requiring each
responsible entity to develop benchmark planning cases using data
consistent with that provided in accordance with the MOD-032 standard,
supplemented by other sources as needed.

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Directive Language

FERC Order 896 Directives

action that involves reducing distribution load during periods of stress to
stabilize the Bulk-Power System, its effect during an extreme weather
event should be modeled.”
P 117: “[I]n addressing this directive, we expect NERC to determine
whether responsible entities will need to take additional steps to ensure
that the impacts of demand load response are accurately modeled in
extreme weather studies, such as by analyzing demand load response as a
sensitivity, as is currently the case under Reliability Standard TPL-001-5.1.”
P124. “[W]e direct NERC to require the use of sensitivity cases to
demonstrate the impact of changes to the assumptions used in the
benchmark planning case. Sensitivity analyses help a transmission planner
to determine if the results of the base case are sensitive to changes in the
inputs. The use of sensitivity analyses is particularly necessary when
studying extreme heat and cold events because some of the assumptions
made when developing a base case may change if temperatures change –
for example, during extreme cold events, load may increase as
temperatures decrease, while a decrease in temperature may result in a
decrease in generation. We… direct NERC to define during the Reliability
Standard development process a baseline set of sensitivities for the new or
modified Reliability Standard. While we do not require the inclusion of any
specific sensitivity in this final rule, NERC should consider including
conditions that vary with temperature such as load, generation, and system
transfers.”

Consideration of Directives

Specifically, Attachment 1 of MOD-032 requires information requested by
the Planning Coordinator or Transmission Planner necessary for modeling
purposes.

This directive is addressed in proposed TPL-008-1 in Requirement R3, which
requires all PCs within the same zone to coordinate to implement a process
for developing benchmark planning cases and sensitivity cases. Sensitivity
cases are used to demonstrate the impact of changes to the basic
assumptions used in the benchmark planning cases. Per Requirement R3
Part 3.4, PCs must include provisions in the case development process to
identify changes to generation, real and reactive forecasted Load, and/or
transfers to develop sensitivity cases.
The identification of changes for sensitivity cases within the coordinated
process of Requirement R3 addresses the directive that precludes
responsible entities from determining sensitivities alone. However, nothing
prevents responsible entities from conducting additional sensitivity studies
they find relevant to their planning areas.

P125. “We do not agree ... that responsible entities alone should determine
the sensitivity cases that must be considered in the responsible entity’s
study. … We…believe that responsible entities should be free to study
additional sensitivities relevant to their planning areas…cooperation will be
necessary between responsible entities conducting extreme heat and
extreme cold weather studies and other registered entities within their
Consideration of FERC Order 896 Directives
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Directive Language

FERC Order 896 Directives

extreme weather study footprints to ensure the selection of appropriate
sensitivities.”
P134. “[W]e directs NERC to require in the new or modified Reliability
Standard the use of planning methods that ensure adequate consideration
of the broad characteristics of extreme heat and cold weather conditions.
We further direct NERC to determine during the standard development
process whether probabilistic elements can be incorporated into the new
or modified Reliability Standard and implemented presently by responsible
entities. If NERC identifies probabilistic elements which responsible entities
can feasibly implement and that would improve upon existing planning
practices, we expect the inclusion of those methods in the proposed
Reliability Standard.”
P138. “[W]e direct NERC to identify during the standard development
process any probabilistic planning methods that would improve upon
existing planning practices, but that NERC deems infeasible to include in
the proposed Reliability Standard at this time. If any such methods are
identified, NERC shall describe in its petition for approval of the proposed
Reliability Standard the barriers preventing the implementation of those
probabilistic elements. We intend to use this information to determine
whether and what next steps may be warranted to facilitate the use of
probabilistic methods in transmission system planning practices.”
P152. “[W]e direct NERC to require in the new or modified Reliability
Standard the development of extreme weather corrective action plans for
specified instances when performance standards are not met. In addition,
as explained below, we direct NERC to develop certain processes to
facilitate interaction and coordination with applicable regulatory
authorities or governing bodies responsible for retail electric service as
appropriate in implementing a corrective action plan.”

Consideration of Directives

The drafting team discussed probabilistic elements and determined while
probabilistic analysis would be a good step forward, it would be better
suited for the future as the methodology, process, and tools mature.
Probabilistic assessment of generation and transmission facilities for the
benchmark planning cases was discussed during the process of drafting the
TPL-008-1 standard. However, based on the actual extreme heat and
extreme cold events that have occurred, outages for generation and
transmission facilities were unique for each of these events. Thus, it was
challenging to draw correlation for the outages that occurred for different
extreme heat and cold events for different regions and different
timeframes. In addition, the data, available from these events, was limited
to perform an adequate probabilistic assessment. Due to these reasons,
the drafting team has decided not to pursue any probabilistic assessment
for the current TPL-008-1 standard. This, however, does not preclude
future development of probabilistic assessment when having additional
data, as well as mature methodology, process and tools that can provide
meaningful probabilistic assessment for generation and transmission
outages under extreme temperature conditions.
The directive is addressed in the proposed TPL-008-1 Requirement R9.
When the benchmark planning case study results indicate the System is
unable to meet performance requirements for P0 and P1 Contingencies,
Corrective Action Plans (CAPs) must be developed. Additionally, in
accordance with Requirement R9 Part 9.1, responsible entities shall make
their CAP available to, and solicit feedback from, applicable regulatory
authorities or governing bodies responsible for retail electric service issues.

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Directive Language

FERC Order 896 Directives

P155: “[T]he Commission is not directing any specific result or content of
the corrective action plan.”
P157. “[W]e direct NERC to require in the new or modified Reliability
Standard the development of corrective action plans that include
mitigation for specified instances where performance requirements for
extreme heat and cold events are not met—i.e., when certain studies
conducted under the Standard show that an extreme heat or cold event
would result in cascading outages, uncontrolled separation, or instability.”
P158: “[W]e give NERC in this final rule the flexibility to specify the
circumstances that require the development of a corrective action plan.”
P165. “[w]e direct NERC to require in the new or modified Reliability
Standard that responsible entities share their corrective action plans with,
and solicit feedback from, applicable regulatory authorities or governing
bodies responsible for retail electric service issues.”
P167. “Further, because an important goal of transmission planning is to
avoid load shed, any responsible entity that includes non-consequential
load loss in its corrective action plan should also identify and share with
applicable regulatory authorities or governing bodies responsible for retail
electric service alternative corrective actions that would, if approved and
implemented, avoid the use of load shedding.”
P188. “[W]e direct NERC to submit a new or modified Reliability Standard
within 18 months of the date of publication of this final rule in the Federal
Register. Further, we direct NERC to propose an implementation timeline
for the new or modified Reliability Standard, with implementation
beginning no later than 12 months after the effective date of a Commission
order approving the proposed Reliability Standard.”

Consideration of Directives

The directive is addressed in the proposed TPL-008-1 Requirement R9.
When the benchmark planning case study results indicate the system is
unable to meet performance requirements for P0 and P1 Contingencies,
Corrective Action Plans must be developed.

The directive is addressed in the proposed TPL-008-1 Requirement R9.
Requirement R9.1 requires the responsible entities to make their CAP
available and solicit feedback from applicable regulatory authorities or
governing bodies responsible for retail electric service issues.
This directive is addressed in proposed TPL-008-1 Requirement R9.
As stipulated in Requirement R9 Part 9.2, when Non-Consequential Load
Loss is utilized as an element of a CAP for a Table 1 P1 Contingency, the
responsible entity must document the alternative(s) considered, and notify
the applicable regulatory authorities or governing bodies responsible for
retail electric service issues.
The directive is addressed with the publication of TPL-008-1 and will be
filed with the regulatory government no later than December 23, 2024,
within 18 months of the date Order No. 896 was published in the Federal
Register.
The implementation plan addresses Requirement R1 becoming effective 12
months from the effective date of the Commission order approving the

Consideration of FERC Order 896 Directives
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Directive Language

FERC Order 896 Directives

P193. “[W]e direct NERC to establish an implementation timeline for the
proposed Reliability Standard. In complying with this directive, NERC will
have discretion to develop a phased-in implementation timeline for the
different requirements of the proposed Reliability Standard (i.e.,
developing benchmark cases, conducting studies, developing corrective
action plans). However, this phased-in implementation must begin within
12 months of the effective date of a Commission order approving the
proposed Reliability Standard and must include a clear deadline for
implementation of all requirements.”

Consideration of Directives

TPL-008-1. In addition, phased-in approaches have been provided for other
Requirements needing additional time. See the TPL-008-1 Implementation
Plan.
The implementation plan addresses Requirement R1 becoming effective 12
months from the effective date of the Commission order approving the
TPL-008-1. In addition, phased-in approaches have been provided for other
Requirements needing additional time. See the TPL-008-1 Implementation
Plan.

Consideration of FERC Order 896 Directives
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Limited Disclosure

DRAFT ERO Enterprise Process for TPL-008-1
Benchmark Weather Event Development and
Maintenance
Standards Development and Engineering Process Document
October 2024

Background

This Electric Reliability Organization (ERO) Enterprise Process for TPL-008-1 1 Benchmark Weather Event
Development and Maintenance addresses how ERO Enterprise staff will develop and maintain a library of
benchmark weather events (herein as the Weather Event Library) to be used by Planning Coordinators and
Transmission Planners for TPL-008-1 studies. Per Requirement R3 of TPL-008-1 and consistent with
directives outlined in FERC Order No. 896 2, Planning Coordinators and Transmission Planners will have
benchmark temperature events available via the Weather Event Library to select from when developing
their benchmark planning cases.

Purpose

The purpose of this process document is to formalize a repeatable approach to develop and maintain the
Weather Event Library. While both the TPL-008-1 study requirements and this process are in the initial
stages of development, it is essential that industry is informed of this process and how it will be designed
and implemented following the completion of NERC Project 2023-07. This process document outlines an
initial set of process objectives and approach but is not considered to be complete at this time. This
document will be revised as needed throughout the development of NERC Project 2023-07.

Document Maintenance

NERC will maintain this document to assure it is consistent with acceptable practices and publicly available.
This document will be reviewed as it is implemented. Updates will be made by NERC Standards
Development and Engineering, as needed, to reflect lessons learned as the process matures. Any
substantive changes to this process, supplemental/attached criteria, or other guidance to be used by NERC
in developing additional benchmark events, archiving/removing benchmark events, or other modifications
to the Weather Event Library, will be reviewed in consultation with NERC Legal, NERC Compliance
Assurance, Zoneal Entity staff, and FERC. Approved substantive revisions to this document will be detailed
in the Appendix, broadly communicated to industry, and included as part of informational filings to FERC.

1
2

Link pending final approval of TPL-008-1
FERC Docket No. RM22-10-000; Order No. 896; https://www.ferc.gov/media/e-1-rm22-10-000; June 15, 2023

RELIABILITY | RESILIENCE | SECURITY

Definitions

Refer to the NERC Glossary of Terms 3 for the below capitalized terms used in this process.
•

Affected Zoneal Entity (ARE)

•

Compliance Enforcement Authority (CEA)

•

Coordinated Oversight

•

Extreme Temperature Assessment (ETA)

•

Lead Zoneal Entity (LRE)

•

Multi-Zone Registered Entity (MRRE)

Process Overview

The following is a five-year iterative process coinciding with Planning Coordinator and Transmission Planner
implementation of TPL-008-1. As TPL-008-1 and associated benchmark event(s) will be submitted to FERC
in December 2024, the first iteration of this process will cover five years (2025—2029).
•

•

•

•

•

December 2024


Weather Event Library developed and ready to go live for industry.



Benchmark Events, for the first five-years required per the TPL-008-1 Reliability Standard,
completed and uploaded to the Weather Event Library.

Year One (2025):


ERO to provide Weather Event Library training.



ERO to engage with industry subject matter experts (SMEs), Planning Coordinators, research
labs, and trade organizations, and NERC technical committees on additional and updated criteria
for developing benchmark events.

Year Two (2026):


ERO to initiate review of benchmark event criteria, identify any changes needed, and
incorporate feedback from year one.



ERO to deliver a webinar on updated criteria for developing benchmark events.

Year Three (2027):


ERO to develop new benchmark events 4 based on updated criteria in year two.



ERO to update the Weather Event Library with updated benchmark events.

Year Four (2028):


3
4

ERO to draft informational filing with FERC.

NERC Glossary of Terms: Glossary_of_Terms.pdf (nerc.com)
Note: This is for the second iteration of benchmark events being developed.

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

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o ERO will engage with industry subject matter experts (SMEs), Planning Coordinators,
research labs, and trade organizations, and NERC technical committees on additional
information needed.
•

Year Five (2029):


ERO to File informational filing with FERC.



ERO to conduct review of this process and make necessary revisions based on lessons-learned
and feedback (e.g., CMEP feedback loops, FERC, SMEs)



ERO to provide training on benchmark event process and changes to the Weather Event Library.

Year 1
Year 2
Year 3
Year4
Year 5

•Deliver Weather Event Library Training
•Develop training and guidance for planning case development

•Review and modify benchmark event criteria
•Informational session on updated criteria

•Update library with new/removed benchmark events

• ERO to draft Informational filing to FERC for any change to criteria and modifications to Weather
Events Library

•Informational filing to FERC for any change to criteria and modifications to Weather Events Library
•Review process and revise based on lessons learned and other feedback loops
•Update Weather Event Library training

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

3

Criteria in Attachment B

Scoping
While the development of the extreme weather event library was intended to be comprehensive, it was
not exhaustive. Instead, this initial assessment is a part of a multi-year effort by NERC and industry to
develop a robust, North American weather dataset and detailed process for extreme weather events. In
the interim, this library of extreme heat and cold events has notable considerations:
• Only extreme heat and cold temperature events were evaluated. The analysis did not assess other
weather events such as hydrologic droughts, wind and solar droughts, wildfires, hurricanes, or other
extreme weather events that could jeopardize grid reliability.
• Only historical meteorological data was considered. The analysis did not incorporate climate
projections or future weather patterns.
• The analysis identified extreme events over a 43-year historical record and did not give higher
priority to recent events
• The study is limited in identifying extreme events, not validating or explaining meteorological drivers
of that event
• The analysis relied on historical reanalysis and modeled weather data rather than historical observed
data for the United States (A smaller observed dataset was used for Canada).
Data Sources
A Pacific Northwest National Laboratory (PNNL) weather dataset 5 used in this study consists of 43 years
(1980-2022) of historical hourly meteorology and roughly 80 years (2020-2099) of projected hourly
meteorology. Hourly observations were dynamically downscaled from historical reanalysis of ERA5 data
into higher temporal and spatial resolutions using the Weather Research and Forecasting Model (WRF). The
model resolution consisted of 12km2 areas that were spatially-averaged by county and then populationweighted to 54 Balancing Authorities (BAs) in the conterminous United States. The variables included in the
final BA weather data are listed in Table 1. While additional parameters like humidity, solar irradiance, and
wind speed are available in the dataset, the identification of extreme weather events in this study was solely
determined by the temperature value.
Table 1: Weather Variables in PNNL Dataset

5 Burleyson, C., Thurber, T., & Vernon, C. (2023). Projections of Hourly Meteorology by Balancing Authority Based on the IM3/HyperFACETS
Thermodynamic Global Warming (TGW) Simulations (v1.0.0) [Data set]. MSD-LIVE Data Repository. https://doi.org/10.57931/1960530

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The PNNL dataset and contributing model were chosen for this study due to the consistency, breadth and
granularity of the weather data. The availability of weather data at the BA-level coincides with topology
standards in power-system coordination in North America. Temperature observation methods can differ
zoneally, so a standardized weather model, such as one in the PNNL dataset, offers unparallelled data
consistency across large geographical areas.
Topology
The zone topology is a function of balancing authority jurisdiction and general knowledge of zoneal weather
patterns. The goal of the topology was to split the North American System into several distinct zones that
have similar electric power system properties (i.e. balancing authority and interconnections) and similar
weather or climatological patterns. Balancing authorities with large areas of jurisdiction, exclusively ISOs
and RTOs, are assigned their own weather zone. In geographical areas comprised of multiple balancing
authorities, generalized weather zones are created to best represent zoneal weather patterns.
Table 2: Balancing Authority to Weather Zone Mappings
Zone
Midwest
New England
Central US
Texas
New York
Central Atlantic
California
Pacific Northwest
Rocky Mountain
Great Basin
Southwest
Southeast
Florida

Balancing Authorities
MISO
ISONE
SPP
ERCOT
NYISO
PJM
5 balancing authorities
10 balancing authorities
3 balancing authorities
4 balancing authorities
6 balancing authorities
7 balancing authorities
9 balancing authorities

In addition to the 13 weather zones representing the United States, three weather zones were developed
to represent Eastern, Central, and Western Canada. The PNNL weather dataset does not contain data for
Canada, so this study compiled observed weather data from weather stations in the lower Canadian
Provinces. The sixteen weather zones best represent the area of study and complement the granularity of
available data. A graphical representation of the final weather zones is shown in Figure 1.
Table 3: Canadian Weather Stations to Weather Zone Mappings

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

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Weather Zones
Eastern Canada
Central Canada
Western Canada

Province
Ontario
Quebec
New Brunswick
Nova Scotia
Saskatchewan
Manitoba
British Columbia
Alberta

Weather Stations
1 weather station
3 weather stations
1 weather station
1 weather station
2 weather stations
1 weather station
2 weather stations
2 weather stations

Figure 1: North American Weather Zones for Extreme Weather Events

Event Selection Process
Extreme weather events are defined in this study as extremely hot or cold multi-day events spanning across
multiple weather zones. The process to select these extreme events used temperature as the sole defining
variable, with emphasis placed on date ranges where multiple weather zones were experiencing historically
hot or cold temperatures.
Aggregating balancing authority data to geographical weather zones
Following the topology detailed above, the hourly temperature observations from either the PNNL weather
dataset or Canadian weather stations are assigned to weather zones. For each balancing area in the United
States, the PNNL data is aggregated from a county-level basis up to the balancing authority based on the

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population in each county. The balancing authority temperature aggregation was therefore provided in the
PNNL dataset.
Additional aggregations were required to develop an average minimum, average, and maximum
temperature for zones with multiple balancing authorities in the Northwest, Southwest, and Southeast. In
these weather zones, the hourly temperature of each balancing authority was weighted by the 2022 peak
load value reported in the EIA Form-861 database. For the Canadian zones, weather station temperature
observations were assigned to the nearest population center and weighted by 2021 Census population.
Calculating Three-Day Rolling Average Min/Max Temperatures
Rather than isolating single hours of extreme weather, the rolling 3-day average of minimum and maximum
daily temperatures are chosen to represent prolonged periods of extreme weather. The three-day
averaging period is centered on every day in the data set (January 1, 1980, to December 31, 2022) and
identifies the average minimum and maximum temperature from the day before, day of, and day after. The
output of this process develops a dataset of multi-day minimum and maximum temperatures to filter out
individual days of extreme heat or cold under the assumption that the power system is more challenged by
sustained periods of extreme heat or cold due to cumulative effects on increasing demand and generator
outages.
Selecting and Ranking Extreme Weather Events by Severity
Once 3-day average temperatures were calculated for every day, the forty coldest minimum values and
forty warmest maximum values were isolated and ranked for each zone, with rank 1 illustrating the most
extreme event. To avoid overlap of events within the same period, any ranked weather events within one
week of another would be removed in favor of the most extreme event. For example, if a zone’s seventhand tenth-most extreme event occur within a 7-day period, only the day with the seventh-most extreme
event would remain in the event database. As a result, some zones may have a discontinuous ranked list
given the removal of “duplicate” events.
A similar one-week overlap method was developed to group contemporaneous extreme weather events
amongst weather zones. First, all event dates were expanded to have a one-week “overlap period” centered
on each date. Then, beginning with the earliest event date, all events that share at least one day of their
overlap periods with the selected event date’s overlap period will be grouped together. The final event date
range will take the earliest and latest dates of all grouped event overlap periods.
The design of the distinct event date ranges encourages multiple weather zones to share extreme weather
events over the course of a one- to two-week event period. To graphically represent the shared extreme
events, all event ranges are listed with the affected zones’ ranks in west-to-east order. A final shortlist of
extreme weather events was developed across all zones. This list included the top one and two most
extreme events, done separately for heat and cold periods. Any event that included at least three zones
experience a top five event simultaneous was also included. For example, if PJM, NYISO, and ISONE all
experienced a top five extreme event, but it was not a top one or two event for any zone in isolation, the
event was included in the final shortlist.

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Results
The result tables show the filtered list of event date ranges with the event ranks for each affected zone; a
lower rank represents a more extreme event and is shaded darker.
Cold Events
The cold events shown in Table 4 demonstrate more concentrated events among nearby zones, with the
most extreme temperature event occurring December 20th to December 29th, 1983. The event uniquely
spanned across the conterminous United States and yielded top ten coldest 3-day average minimum
temperatures in 10 different weather zones.
Under these results, the following cold events are recommended for the NERC library:
• 12/17/1990 – 1/2/1991 for the Western U.S. and Canada
o 12/21 for Pacific NW
o 12/22 for Rocky Mountain, Great Basin, California
o 12/23 for Southwest
o 12/29 for Western Canada
• 12/19/1989 – 12/27/1989 for Central and Southeast U.S. and Canada
o 12/23 for Central Canada
o 12/24 for Central US
o 12/25 for Texas, Midwest, Southeast
o 12/26 for Florida
• 1/13/1994 – 1/29/1994 for the Northeast U.S. and Canada
o 1/16 for New England, Eastern Canada
o 1/20 for Central Atlantic, New York
Table 4: Shortlist of Cold Events

It is important to note that these weather events do not affect all zones simultaneously, but instead move
across the continent in predictable patterns. This has important implications for power system operations
and reliability as load and generator availability may be affected in different zones in different times. An
example of this is from the 1983 event shown geographically in Figure 2. In this example, the worst case
does not occur at the same time in each zone and ideally multiple time periods should be assessed by the
planning coordinators.

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Figure 2: Snippets of Animated Weather Event Temperature Map

Heat Events
The heat events shown in Table 5 are more numerous and disparate from one another. In other words,
while extreme cold events tend to affect large geographies simultaneously, heat events can be more
localized. The unconcentrated nature of heat events makes selecting the most extreme event more
ambiguous.
Under these results, the following heat events are recommended for the NERC library:

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•

•

•

7/13/2006 – 7/26/2006 for the Western U.S. and Canada
o 7/16 for Rocky Mountain, Great Basin
o 7/22 for Western Canada, Pacific NW
o 7/23 for California, Southwest
6/21/2012 – 7/9/2012 for Central and Southeast U.S. and Canada
o 6/26 for Texas
o 6/28 for Central Canada, Central US
o 6/30 for Southeast, Florida
o 7/5 for Midwest
7/16/2021 – 7/25/2021 for the Northeast U.S. and Canada
o 7/21 for Central Atlantic, Eastern Canada
o 7/22 for New York, New England
Table 5: Shortlist of Heat Events

Recommendations
The results of this study should inform planning coordinators of potential dates of when to study power
system conditions under extreme weather scenarios. While the final selection of event date ranges aligns
with historical records of extreme weather, a few recommendations and considerations should be made
before proceeding with this study’s results.
• Planning coordinators should assess the entire list of distinct events shown and determine which
events were the most extreme for their jurisdiction along with neighboring areas
• Modelled temperature data provides widespread consistency of weather data across many years
and many zones. Observed temperature data can recognizably vary from modelled values due to
the variety of observation methods at individual weather stations. The temperatures derived from
the PNNL dataset for the extreme weather event selection can be provided, but actual temperature
values used in planning scenarios may need to be derived from observed weather records for local
consistency.

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•
•
•

While temperature is a strong indicator of extreme weather events, it is not the only indicator
available in historical weather data sets. The inclusion of other weather variables such as humidity
and wind speed could further quantify the severity of extreme weather events.
Care should be taken when developing wind, solar, and generator outage assumptions in the
planning cases, using meteorological information to dispatch.
Exceptions need to be accounted for – including HVDC and switchable units.

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Limited Disclosure

Attachment B: Criteria used to develop the
benchmark events
Criteria

Criteria for benchmark events to be drafted.

TPL-008-1 ERO Enterprise Benchmark Weather Event Development and Maintenance
Process Document Version History
Version
1

Date
TBD

Owner
Standards Staff

Change tracking
Initial Version

RELIABILITY | RESILIENCE | SECURITY

TPL-008-1 Benchmark Temperature Events
November 2024

The below provides extreme heat and extreme cold benchmark temperature event data per the zones identified in Attachment 1 of the TPL008-1 Standard. Should entities not agree with the data provided below, you are welcome to coordinate with all Planning Coordinators within
your zone to developing one common extreme heat benchmark temperature event and one common extreme cold benchmark temperature
event per Requirement R2.
Zone

Daily Data

Canada Central
Florida
ISO-NE
Maritimes
MISO North
MISO South
NYISO
Ontario
PJM
SERC
SPP North
SPP South

Daily
Daily
Daily

California/Mexico
Great Basin
Rocky Mtn
Pacific NW

Daily
Daily
Daily
Daily

Daily
Daily
Daily

Daily
Daily
Daily
Daily
Daily
Daily

Benchmark Events
Top 40 Hottest/Coldest 3-Day Average
Eastern Interconnection
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Western Interconnection
Top 40
Top 40
Top 40
Top 40

Hourly Data Selected Events
N/A
Hourly
Hourly
N/A
Hourly
Hourly
Hourly
N/A
Hourly
Hourly
Hourly
Hourly
Hourly
Hourly
Hourly
Hourly

RELIABILITY | RESILIENCE | SECURITY

WECC Southwest
Canada West

Daily
Daily

ERCOT

Daily

Quebec

Daily

TPL-008-1 Benchmark Temperature Events | November 2024

ERCOT Interconnection
Quebec Interconnection

Top 40
Top 40

Hourly
N/A

Top 40

Hourly

Top 40

N/A

NERC TPL-008 Data Library Documentation
Daily Data
Daily temperature statistics by Weather Zone.
● Region: The weather region associated with the data
● Date: Date in mm/dd/yyyy format
● Daily_Min_Temp: Minimum hourly temperature recorded on the associated date (F)
● Daily_Avg_Temp: Average hourly temperature recorded on the associated date (F)
● Daily_Max_Temp: Minimum hourly temperature recorded on the associated date (F)
● 3_Day_Rolling_Avg_Max_Temp: Three-day rolling average of daily maximum temperature (F)
● 3_Day_Rolling_Avg_Min_Temp: Three-day rolling average of daily minimum temperature (F)

Top 40 Events
Top 40 hottest and coldest days in each weather zone, measured by 3-day rolling average temperatures
● Region: The weather region associated with the data
● Event_Type: Heat Event or Cold Event
● Year: Year of associated event
● Month: Month of associated event
● Date: Date of associated event in mm/dd/yyyy format
● Daily_Min_Temp: Minimum hourly temperature recorded on the associated date (F)
● Daily_Avg_Temp: Average hourly temperature recorded on the associated date (F)
● Daily_Max_Temp: Minimum hourly temperature recorded on the associated date (F)
● 3_Day_Rolling_Avg_Max_Temp: Three-day rolling average of daily maximum temperature (F)
● 3_Day_Rolling_Avg_Min_Temp: Three-day rolling average of daily minimum temperature (F)
● Event_Temp: Temperature used to benchmark weather event (3_Day_Rolling_Avg_Max_Temp for Heat
Events, 3_Day_Rolling_Avg_Min_Temp for Cold Events)

Hourly Data (Filtered)
Hourly weather data from PNNL Dataset with modifications. Values are weighted if the region was represented by
multiple BAs. Values are filtered to only include Top 40 event days. Temperature converted from Kelvin to
Fahrenheit.
● Region: The weather region associated with the data
● Time_UTC: Datetime of hourly data in UTC timezone
● Temperature_F: Hourly temperature measured at 2-m (F)
● Q2: Specific humidity measured as 2-m water vapor mixing ratio (kg/kg)
● SWDOWN: Shortwave radiation measured as downwelling shortwave radiative flux at the surface (W/m²)
● SLW: Longwave radiation measured as radiative flux at the surface (W/m²)
● WSPD: Wind speed measured as 10-m wind speed (m/s)
For original data, including hourly data by county and balancing authority, please refer to:
Burleyson, C., Thurber, T., & Vernon, C. (2023). Projections of Hourly Meteorology by Balancing Authority Based on
the IM3/HyperFACETS Thermodynamic Global Warming (TGW) Simulations (v1.0.0) [Data set]. MSD-LIVE Data
Repository. https://doi.org/10.57931/1960530

Weather Zones

2

Public

Standards Announcement

Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather
Formal Comment Period Open through November 21, 2024
Now Available

A 15-day formal comment period for draft four of TPL-008-1 – Transmission System Planning
Performance Requirements for Extreme Temperature Events is open through 8 p.m. Eastern,
Thursday, November 21, 2024.
The Standards Committee approved waivers to the Standards Process Manual at their December
2023 meeting. These waivers were sought by NERC Standards for reduced formal comment and
ballot periods to assist the drafting teams in expediting the standards development process due to
firm timeline expectations set by FERC Order 896.
The standard drafting team’s considerations of the responses received from the previous comment
period are reflected in this draft of the standard.
Reminder Regarding Corporate RBB Memberships

Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more than
the one permitted representative in a particular Segment must withdraw the duplicate membership(s)
prior to joining new ballot pools or voting on anything as part of an existing ballot pool. Contact
[email protected] to assist with the removal of any duplicate registrations.
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. An unofficial Word
version of the comment form is posted on the project page.
•

Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.

•

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

Public

Next Steps

Additional ballots for the standard and implementation plan, as well as a non-binding poll of the
associated Violation Risk Factors and Violation Severity Levels will be conducted November 12-21,
2024.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Jordan Mallory (via email) or at
404-479-7358. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists"
from the "Service" drop-down menu and specify “Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather observer list” in the Description Box.

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 2023-07 Transmission Planning Performance Requirements for Extreme Weather | November 7, 2024

2

Comment Report
Project Name:

2023-07 Transmission Planning Performance Requirements for Extreme Weather | Draft 4

Comment Period Start Date:

11/7/2024

Comment Period End Date:

11/21/2024

Associated Ballots:

2023-07 Transmission Planning Performance Requirements for Extreme Weather Implementation Plan AB 4 OT
2023-07 Transmission Planning Performance Requirements for Extreme Weather TPL-008-1 AB 4 ST

There were 50 sets of responses, including comments from approximately 140 different people from approximately 89 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. The Drafting Team (DT) updated Requirement R2 based on comments received. Do you agree? If you do not agree, please provide your
recommendation and, if appropriate, technical or procedural justification.
2. The DT updated Requirement R9 based on comments received. Do you agree? If you do not agree, please provide your recommendation
and, if appropriate, technical or procedural justification.
3. The DT updated Attachment 1 based on comments received. Do you agree? If you do not agree, please provide your recommendation and,
if appropriate, technical or procedural justification.
4. The DT believes proposed modifications in TPL-008-1 provide entities with flexibility to meet the reliability objectives in a cost-effective
manner. Do you agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost-effective approaches,
please provide your recommendation and, if appropriate, technical or procedural justification.
5. Provide any additional comments for the drafting team to consider, including the provided technical rationale document, if desired.

Organization
Name

Name

BC Hydro and Adrian
Power
Andreoiu
Authority

MRO

Anna
Martinson

Segment(s)

1

1,2,3,4,5,6

Region

WECC

MRO

Group Name

BC Hydro

MRO Group

Group Member
Name

Group
Member
Organization

Group
Member
Segment(s)

Group Member
Region

Hootan Jarollahi

BC Hydro and 3
Power
Authority

WECC

Helen Hamilton
Harding

BC Hydro and 5
Power
Authority

WECC

Adrian Andreoiu

BC Hydro and 1
Power
Authority

WECC

Shonda McCain

Omaha Public 1,3,5,6
Power District
(OPPD)

MRO

Michael Brytowski Great River
Energy

1,3,5,6

MRO

Jamison Cawley

Nebraska
Public Power
District

1,3,5

MRO

Jay Sethi

Manitoba
Hydro (MH)

1,3,5,6

MRO

Husam Al-Hadidi

Manitoba
1,3,5,6
Hydro
(System
Preformance)

MRO

Kimberly Bentley

Western Area 1,6
Power
Adminstration

MRO

Jaimin Patal

Saskatchewan 1
Power
Coporation
(SPC)

MRO

George Brown

Pattern
Operators LP

5

MRO

Larry Heckert

Alliant Energy 4
(ALTE)

MRO

Terry Harbour

MidAmerican
Energy
Company
(MEC)

1,3

MRO

Dane Rogers

Oklahoma
Gas and
Electric
(OG&E)

1,3,5,6

MRO

Exelon
Independent
Electricity
System
Operator

Eversource
Energy

Public Utility
District No. 1
of Chelan
County

Daniel Gacek 1
Helen Lainis

2

Joshua London 1

Joyce Gundry

3

Exelon
IRC SRC

Eversource

CHPD

Seth Shoemaker

Muscatine
Power &
Water

1,3,5,6

MRO

Michael Ayotte

ITC Holdings

1

MRO

Andrew Coffelt

Board of
1,3,5,6
Public UtilitiesKansas (BPU)

MRO

Peter Brown

Invenergy

MRO

Angela Wheat

Southwestern 1
Power
Administration

MRO

Joshua Phillips

Southwest
Power Pool

2

MRO

Patrick Tuttle

Oklahoma
Municipal
Power
Authority

4,5

MRO

Daniel Gacek

Exelon

1

RF

Kinte Whitehead

Exelon

3

RF

Bobbi Welch

Midcontinent
ISO, Inc.

2

MRO

Gregory Campoli New York
Independent
System
Operator

2

NPCC

Helen Lainis

IESO

2

NPCC

Charles Yeung

SPP

2

SERC

Elizabeth Davis

PJM

2

RF

Joshua London

Eversource
Energy

1

NPCC

Vicki O'Leary

Eversource
Energy

3

NPCC

Rebecca Zahler

Public Utility
District No. 1
of Chelan
County

5

WECC

Joyce Gundry

Public Utility
District No. 1
of Chelan
County

3

WECC

Diane Landry

Public Utility
District No. 1

1

WECC

5,6

of Chelan
County

FirstEnergy FirstEnergy
Corporation

Black Hills
Corporation

Northeast
Power
Coordinating
Council

Mark Garza

4

Rachel Schuldt 6

Ruida Shu

1,2,3,4,5,6,7,8,9,10 NPCC

Tamarra Hardie

Public Utility
District No. 1
of Chelan
County

6

WECC

Julie Severino

FirstEnergy FirstEnergy
Corporation

1

RF

Aaron
Ghodooshim

FirstEnergy FirstEnergy
Corporation

3

RF

Robert Loy

FirstEnergy FirstEnergy
Solutions

5

RF

Mark Garza

FirstEnergyFirstEnergy

1,3,4,5,6

RF

Stacey Sheehan

FirstEnergy FirstEnergy
Corporation

6

RF

Black Hills
Travis Grablander Black Hills
Corporation Corporation
All Segments Josh Combs
Black Hills
Corporation

1

WECC

3

WECC

Rachel Schuldt

Black Hills
Corporation

6

WECC

Carly Miller

Black Hills
Corporation

5

WECC

Sheila Suurmeier Black Hills
Corporation

5

WECC

Gerry Dunbar

Northeast
Power
Coordinating
Council

10

NPCC

Deidre Altobell

Con Edison

1

NPCC

Michele Tondalo

United
Illuminating
Co.

1

NPCC

Stephanie UllahMazzuca

Orange and
Rockland

1

NPCC

Michael Ridolfino Central
1
Hudson Gas &
Electric Corp.

NPCC

FE Voter

NPCC RSC

Randy Buswell

Vermont
1
Electric Power
Company

NPCC

James Grant

NYISO

2

NPCC

Dermot Smyth

Con Ed 1
Consolidated
Edison Co. of
New York

NPCC

David Burke

Orange and
Rockland

3

NPCC

Peter Yost

Con Ed 3
Consolidated
Edison Co. of
New York

NPCC

Salvatore
Spagnolo

New York
Power
Authority

1

NPCC

Sean Bodkin

Dominion Dominion
Resources,
Inc.

6

NPCC

Silvia Mitchell

NextEra
1
Energy Florida Power
and Light Co.

NPCC

Sean Cavote

PSEG

4

NPCC

Jason Chandler

Con Edison

5

NPCC

Tracy MacNicoll

Utility Services 5

NPCC

Shivaz Chopra

New York
Power
Authority

6

NPCC

Vijay Puran

New York
6
State
Department of
Public Service

NPCC

David Kiguel

Independent

7

NPCC

Joel Charlebois

AESI

7

NPCC

Joshua London

Eversource
Energy

1

NPCC

Jeffrey Streifling

NB Power
Corporation

1,4,10

NPCC

Joel Charlebois

AESI

7

NPCC

John Hastings

National Grid

1

NPCC

Shannon
Mickens

Tim Kelley

Shannon
Mickens

Tim Kelley

MRO,SPP
RE,WECC

WECC

SPP RTO

SMUD and
BANC

Erin Wilson

NB Power

1

NPCC

James Grant

NYISO

2

NPCC

Michael
Couchesne

ISO-NE

2

NPCC

Kurtis Chong

IESO

2

NPCC

Michele Pagano

Con Edison

4

NPCC

Bendong Sun

Bruce Power

4

NPCC

Carvers Powers

Utility Services 5

NPCC

Wes Yeomans

NYSRC

7

NPCC

Shannon Mickens Southwest
Power Pool
Inc.

2

MRO

Mia Wilson

Southwest
Power Pool
Inc.

2

MRO

Eddie Watson

Southwest
Power Pool
Inc.

2

MRO

Erin Cullum

Southwest
Power Pool
Inc.

2

MRO

Jonathan Hayes

Southwest
Power Pool
Inc.

2

MRO

Jeff McDiarmid

Southwest
Power Pool
Inc.

2

MRO

Scott Jordan

Southwest
Power Pool
Inc

2

MRO

Mason Favazza

Southwest
Power Pool
Inc

2

MRO

Zach Sabey

Southwest
Power Pool
Inc

2

MRO

Josh Phillips

Southwest
Power Pool
Inc.

2

MRO

Nicole Looney

Sacramento
Municipal
Utility District

3

WECC

Charles Norton

Sacramento
Municipal
Utility District

6

WECC

Wei Shao

Sacramento
Municipal
Utility District

1

WECC

Foung Mua

Sacramento
Municipal
Utility District

4

WECC

Nicole Goi

Sacramento
Municipal
Utility District

5

WECC

Kevin Smith

Balancing
Authority of
Northern
California

1

WECC

1. The Drafting Team (DT) updated Requirement R2 based on comments received. Do you agree? If you do not agree, please provide your
recommendation and, if appropriate, technical or procedural justification.
Adrian Andreoiu - BC Hydro and Power Authority - 1, Group Name BC Hydro
Answer

No

Document Name
Comment
BC Hydro appreciates the drafting team's efforts and opportunity to comment, and offers the following comments.
(1) The ERO is not subject to TPL-008-1 regulatory compliance. Entities are relying on the ERO’s infrastructure and commitment to maintain the
benchmark temperature event library. As drafted, a PC can be in a potential noncompliance if they choose to use a benchmark event from the EROmaintained library, and the event is not meeting the specifications per Parts 2.1 and 2.2.
BC Hydro is requesting that the drafting team in conjunction with the ERO document the controls that will be in place to maintain the library. These
controls should include the location of the library and quality checks to ensure the events in the library meet R2 Parts 2.1 and 2.2.
BC Hydro recommends revising the language of R2 Parts 2.1 and 2.2 to apply if a PC develops their own benchmark events, and not apply to the ERO
benchmark events library.
(2) A Planning Coordinator may be in a potential noncompliance if another PC is not participating in the required coordination and assessment
activities, which may be the case as different jurisdictions (such as Canada and US, or even between BC and Alberta within Canada) have different
standard adoption timelines.
BC Hydro suggests that the Implementation Plan include provisions that allow for compliance enforcement only when TPL-008-1 is effective in all
applicable jurisdictions.
Alternatively, the Canada West zone should be split into a BC-only zone. This may help alleviate compliance risks and it will also help creating a more
robust ETA given the different geographic areas and weather zones across the Canadian provinces of BC and Alberta.
There could also be scenario where in a multiple PC zone there may one PC that does not participate in the coordination, or there is no agreement on a
common event. In such a scenario, all PCs may be found in noncompliance.
BC Hydro recommends that the standard include provisions to allow for conflict resolution.
Likes

0

Dislikes

0

Response
Richard Vendetti - NextEra Energy - 5
Answer
Document Name
Comment

No

NextEra does not agree with the modifications to R2. The SAR references the use of either “a projected frequency (e.g., 1-in-50-year event); or a
probability distribution (95th percentile event).” The development of extreme events refers to foot note 9 “Benchmark events will form the basis for a
planner's benchmark planning case— i.e., the base case representing system conditions under the relevant benchmark event—that will be used to
study the potential wide-area impacts of anticipated extreme heat and cold weather events.”
FERC via the SAR requested to develop a base case that is representative of system conditions which could be a 1 in 50 year or a P95
event. Following the proposed language in the standard and the ERO library, the warmest temperature Florida could use for its winter assessment is
32.3 degrees and the lowest being 24.9F. The concern is that the entire state is at freezing temperatures and will generate significant winter loads in
Florida much larger than the 20% sensitivity we use for winter, thereby generating transmission projects that will not provide value to our customers.
NextEra does not consider this a P95 event, especially if the average 3 rolling day is taking into consideration (also not requested by the SAR). The
coldest temperature experienced in Miami over the last 40 years was during the winter of 1989, where temperatures were as low as 30 degrees. The
lowest 3 day rolling average was 32.6 degrees (12/23-27F, 12/24-31F, 12/25-30F and 12/27-38F). The standard as written will force NextEra to plan to
a greater than P100 winter loads. This is an un-realistic approach, considering most of Florida’s load is located in Southern Florida south of Lake
Okeechobee. NextEra recommends the language in R2 to state “Represent the 95th percentile extreme conditions for the climate zone based on the 3day rolling average of maximum (heat) or minimum (cold) temperature across the zone.”
Likes

0

Dislikes

0

Response
Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
R2.2, "Represent one of the 20 most extreme temperature conditions based on the three-day rolling average of daily maximum (heat) or daily minimum
(cold) temperature across the zone," is far too lax. Selecting the 20th most severe event of the past four decades would not constitute much of a
challenge.
Likes

0

Dislikes

0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy Houston Electric, LLC (CEHE) believes with the current zone designations, there are some zones where temperature differences
would be significant due to their very large north/south geographical spans. A concern arises whether the chosen extreme temperature event case is
applicable to the overall zone in these cases. It might not be representative of certain parts of the zone. Transmission Planners should be involved in

the selection. CEHE recommends the following revision: Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall select
which extreme heat and extreme cold weather events to develop benchmark extreme temperature events applicable to their region.
Likes

0

Dislikes

0

Response
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer

No

Document Name
Comment
SPP opposes splitting our region into North and South zones. As a contiguously integrated system, our system does not demarcate at state lines
boundaries. We recently completed our 2024 Integrated Transmission Plan that resulted in $7.5B in network upgrades to further strengthen this
integration.
The standard as written could require SPP to select a high and low temperature extreme in both the northern region and southern region, creating a
situation where we are disconnecting the interconnections we built and those planned to in the future. This results in a needless complication to the
existing systems and creates an unnecessary burden that does not improve reliability. As proposed in the previous version of the document, we request
the Planning Coordinator zone be reestablished into a contiguous system for evaluating these extreme events. The bifurcation is even less appropriate
when considering the events proposed in the ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance
indicate using an event that overlaps both SPP regions from December 24, 1989. Conversely, the proposed extreme heat case only affected the
proposed SPP South Region.
If required to use two zones, we would like to see clarification in the language that indicates regions are allowed to utilize the same scenario provided it
meets the requirements in 2.1 and 2.2.

Likes

0

Dislikes

0

Response
Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

Yes

Document Name
Comment
We have some comments / observations regarding Req #2 that we would like to share with the SDT:

In Req #2 language, the word ‘select’ has been replaced by ‘identify’. However, we observe that the word ‘select’ is still utilized in the Measure
#2 language, the Req #3 language and in the Technical Rationale document. This inconsistency could cause some confusion about the actual intent.
For example, the word ‘identify’ might better imply the coordination that is allowed by Req #2.
The Technical Rationale should be updated to highlight and clarify the significance of this wording change.

Req #2 states that the benchmark temperature events shall be obtained from the benchmark library maintained by the ERO or developed by the
Planning Coordinators. Is this implying that some of the benchmark events may not be available on the library after they are developed by the PCs? If
so, is there any expectation (or should there be any) that these benchmark events be somewhat communicated/shared to other PCs for awareness if
they are developed and not on the benchmark library?
Likes

0

Dislikes

0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
Comment
FirstEnergy has no concerns with the update to Requirement R2.
Likes

0

Dislikes
Response

0

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Texas RE recommends revising Measure M2 from “…to select one common extreme heat benchmark temperature event” to “to identify one common
extreme heat benchmark temperature event. This makes the language consist with the revision made to Requirement R2.
Likes

0

Dislikes

0

Response
Sharon Darwin - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Southern Company supports EEI’s comments.
Likes

0

Dislikes

0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

Yes

Document Name
Comment
ITC supports the proposed changes made to Requirement R2.
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 made to Requirement R2, which empowers the Planning Coordinator to develop the benchmark temperature events rather
then solely depending on the benchmark temperature events contained in the benchmark library.
Likes

0

Dislikes

0

Response
Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer

Yes

Document Name
Comment
PNM & TNMP supports EEI’s comments and supports R2.
Likes

0

Dislikes

0

Response
Daniel Gacek - Exelon - 1, Group Name Exelon
Answer

Yes

Document Name
Comment
Exelon agrees with the updated proposed TPL-008 Reliability Standard Requirement R2. Additionally, are there any plans to add guidance regarding
“most extreme temperature conditions” in section 2.2? Can a planning coordinator come up with its own criteria/metric considering that they are likely a
broad range of temperatures throughout the weather zone(s) for each temperature events?
Likes

0

Dislikes

0

Response
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer

Yes

Document Name
Comment
Ameren agrees with EEI's comments.
Likes

0

Dislikes

0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
None.
Likes

0

Dislikes

0

Response
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer

Yes

Document Name
Comment
See EEI Comments
Likes

0

Dislikes

0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment

Yes

See EEI Comments
Likes

0

Dislikes

0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

Yes

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) on question 1
Likes

0

Dislikes

0

Response
Helen Lainis - Independent Electricity System Operator - 2, Group Name IRC SRC
Answer

Yes

Document Name
Comment
The ISO/RTO Council Standards Review Committee (IRC SRC) generally agrees with the revisions to Requirement R2, and recommends the following
additional revisions to further clarify the Requirement:
Revise the second-to-last sentence at the end of R2 as follows to reference PCs first and the ERO benchmark library second to avoid a possible
inference that the PC is required to develop its own benchmark library:
“The benchmark temperature events shall be developed by the Planning Coordinators or obtained from the benchmark library maintained by the ERO.”
Revise the last sentence at the end of R2 to read as follows to better reflect the fact that the Planning Coordinator (rather than the benchmark
temperature event) is ultimately the entity making the considerations described in Parts 2.1 and 2.2: “The Planning Coordinator’s selection of each
benchmark temperature event shall:”
Revise Part 2.2 as follows to clarify that the temperature conditions referenced in Part 2.2 are required to fall within the time period referenced in
Part 2.1: “Represent one of the 20 most extreme temperature conditions within the period identified in Part 2.1 based on the three-day rolling
average…”
Likes

0

Dislikes

0

Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
ERCOT joins the comments submitted by the ISO/RTO Council (IRC) Standards Review Committee (SRC) for this question and adopts them as its
own.
Likes

0

Dislikes

0

Response
Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer

Yes

Document Name
Comment
AEPC has signed on to ACES comments. Please review ACES comments.
Likes

0

Dislikes

0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Junji Yamaguchi, Hydro-Quebec (HQ), 1, 5; Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal
Mazza
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 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
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Nazra Gladu - Manitoba Hydro - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

Response
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Kevin Conway - Western Power Pool - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Joshua London - Eversource Energy - 1, Group Name Eversource
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
Document Name

Yes

Comment
Likes

0

Dislikes

0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Greg Sorenson - Greg Sorenson On Behalf of: Tremayne Brown, ReliabilityFirst , 10; - Greg Sorenson
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 NPCC RSC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
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
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer
Document Name
Comment
Abstain
Likes

0

Dislikes
Response

0

2. The DT updated Requirement R9 based on comments received. Do you agree? If you do not agree, please provide your recommendation
and, if appropriate, technical or procedural justification.
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer

No

Document Name
Comment
The current language in R9.4 says revisions to Corrective Action Plans are limited to the subsequent Extreme Temperature Assessments, yet the
underlying system may have change identified through system upgrades. These Corrective Action Plans should be more flexible in the event a system
upgrade is completed or a separate assessment demonstrates the underlying performance issue has been mitigated. The inclusion of “or other planning
assessments” in 9.4 appeared amicable during the drafting team discussion, and we request this be adopted as proposed in the following revision:
9.4. Be permitted to have revisions to the Corrective Action Plan in subsequent Extreme Temperature Assessments or other planning assessments,
provided that the planned Bulk Electric System shall continue to meet the performance requirements of Table 1.

Likes

0

Dislikes

0

Response
Mark Flanary - Midwest Reliability Organization - 10
Answer

No

Document Name
Comment
MRO is not confortable with two parts of R9.3, both of which limit signicantly the region's ability to meaningfully enforce the requirement:
1. The terms “regulatory authorities” and “governing bodies” are not specific
2. There are no timning requirements prescribed for the responsible entity concerning when the responsible entity must make its Corrective Action Plan
available to, and solicit feedback from, applicable regulatory authorities or governing bodies responsible for retail electric service issues.
Likes

0

Dislikes

0

Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2

Answer

No

Document Name
Comment
ERCOT joins the comments submitted by the IRC SRC for this question and adopts them as its own.
Likes

0

Dislikes

0

Response
Helen Lainis - Independent Electricity System Operator - 2, Group Name IRC SRC
Answer

No

Document Name
Comment
The current language in R9.4 says revisions to Corrective Action Plans are limited to subsequent Extreme Temperature Assessments. However, the
underlying system may change between assessments because of system upgrades. These Corrective Action Plans should be more flexible in the
event a system upgrade is completed or a separate assessment demonstrates the underlying performance issue has been mitigated. The inclusion of
“or other planning assessments” in 9.4 appeared to be acceptable during the drafting team discussion, and we request this be adopted as proposed in
the following revision:
a. 9.4. Be permitted to have revisions to the Corrective Action Plan in subsequent Extreme Temperature Assessments or other planning
assessments, provided that the planned Bulk Electric System shall continue to meet the performance requirements of Table 1.
Likes

0

Dislikes

0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
The current draft is not clear what the timeframe is for providing the CAP in R9.1. In addition, there is no timeframe when to notify the applicable
regulatory authorities or governing bodies in R9.2. CEHE strongly disagrees with the following statement in R9.3: “Make its Corrective Action Plan
available to, and solicit feedback from, applicable regulatory authorities or governing bodies responsible for retail electric service issues.” CEHE
recommends that “applicable regulatory authorities or governing bodies” be defined. CEHE also recommends that TPs should be providing CAP
information only to their PC.
Likes

0

Dislikes

0

Response
Richard Vendetti - NextEra Energy - 5
Answer

No

Document Name
Comment
NextEra does not agree with the language of R9.3 regarding the solicitation of feedback, as this is in line and satisfied through R11 of the standard.
Likes

0

Dislikes

0

Response
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

No

Document Name
Comment
During the recent revisions, a proposal was made with support to clarify 9.4 that revisions to a Corrective Action Plan should be allowed if other
planning assessments resolve the concern. As such this should be captured in requirement 9.4 such as the following:
9.4. Be permitted to have revisions to the Corrective Action Plan in subsequent Extreme Temperature Assessments or other planning assessments,
provided that the planned Bulk Electric System shall continue to meet the performance requirements of Table 1.
Likes

1

Dislikes

Scott Brame, N/A, Brame Scott
0

Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
•
•

The purpose and required response actions related to the sharing of CAPs and solicitation of feedback is not clear.
Documentation of alternatives is an additional administrative burden and provides little benefit to reliability. It is also unclear if there is some
type of expectation these alternatives are reviewed or potentially challenged as invalid.

•
•
•

The role of the TO and/or GO in implementing or otherwise responding to CAPs that may require additions or modifications to their
systems/facilities is not captured in these requirements.
There appears to be a significant amount of outside review required but no clear actions the responsible entity is required to take, particularly if
there is a dispute. What is the purpose of the review and the expected response? This potentially produces an undue burden on the PC/TP
and adds subjectivity in requiring a review with no documented guidelines for conducting the review.
GTC recommends the restructuring of requirement 9 such that documentation of alternatives along with the sharing and soliciting feedback
back is only necessary when utilizing Non-Consequential Load Loss as an interim solution.

Likes

0

Dislikes

0

Response
Joshua London - Eversource Energy - 1, Group Name Eversource
Answer

No

Document Name
Comment
Eversource has concerns regarding compliance with Requirement R9.3. Because this standard is focused on “Extreme Temperature Events”, the
company can foresee issues with regulatory agencies not wanting the company to invest significant funds into these issues. What would occur if
Eversource supplied a CAP to the appropriate governing body and they state they do not agree the work is necessary? Would creating the CAP still
meet the intent of the requirement although it may not be allowed to be implemented? Eversource recommends the DT consider adding language in
case such a scenario arises.
Likes

0

Dislikes

0

Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
We recommend that further clarification be given to how “applicable” regulatory authorities or governing bodies are determined.
Likes

0

Dislikes

0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton

Answer

No

Document Name
Comment
Oncor strongly disagrees with the following statement in R9.3: “Make its Corrective Action Plan available to, and solicit feedback from, applicable
regulatory authorities or governing bodies responsible for retail electric service issues.” We propose that “applicable regulatory authorities or governing
bodies” be defined and limited. For example, a TP should only need to provide their PC with CAP information.
Likes

0

Dislikes

0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
1) Based on other projects that include developing and implementing CAPs, USV does not agree with the proposed modifications and would feel more
confident if there were guidelines and more structured timelines set for the CAPs. Perhaps not in the standard itself, but guidance on timelines could be
explained in the technical rationale and include timelines for implementing CAPs and when entities can utilize backup action plans such as NonConsequential Load Loss.

2) The newly proposed modifications to R9 compared to the proposed modifications from the previous draft do not change the obligations for
responsible entities. The new requirement 9.3 is administrative in nature and does not appear to provide any increase in reliability, if anything it would
delay the implementation of the CAP. USV understands the directives in FERC order 896 and the need for R9. However, we disagree that any
significant improvements have been made to previously proposed R9 modifications.
Likes

0

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0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Document Name
Comment

Yes

Evergy supports and incorporates by reference the comments of the Midwest Reliability Organization's NERC Standards Review Forum (MRO
NSRF) on question 2
Likes

0

Dislikes

0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

Yes

Document Name
Comment
See EEI Comments
Likes

0

Dislikes

0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
None.
Likes

0

Dislikes

0

Response
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer
Document Name
Comment
Ameren agrees with EEI's comments.

Yes

Likes

0

Dislikes

0

Response
Daniel Gacek - Exelon - 1, Group Name Exelon
Answer

Yes

Document Name
Comment
Exelon agrees with the updated proposed TPL-008 Reliability Standard Requirements R9.
Likes

0

Dislikes

0

Response
Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer

Yes

Document Name
Comment
PNM & TNMP agrees with R9.
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 made to Requirement R9 and offers no additional changes.
Likes
Dislikes

0
0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

Yes

Document Name
Comment
ITC supports the proposed changes made to Requirement R9.
Likes

0

Dislikes

0

Response
Sharon Darwin - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Southern Company supports EEI’s comments.
Likes

0

Dislikes

0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
Comment
FirstEnergy has no concerns with the update to Requirement R9.
Likes

0

Dislikes
Response

0

Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Dwanique Spiller - Berkshire Hathaway - NV Energy - 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 NPCC RSC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Greg Sorenson - Greg Sorenson On Behalf of: Tremayne Brown, ReliabilityFirst , 10; - Greg Sorenson
Answer

Yes

Document Name
Comment
Likes

0

Dislikes
Response

0

Donald Lock - Talen Generation, LLC - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Kevin Conway - Western Power Pool - 4

Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Nazra Gladu - Manitoba Hydro - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,

6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Junji Yamaguchi, Hydro-Quebec (HQ), 1, 5; Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal
Mazza
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Document Name
Comment
See EEI Comments
Likes

0

Dislikes

0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name

Comment
Texas RE continues to recommend including a timeframe for which the CAPs need to be developed and implemented once the benchmark planning
case study results indicate the System is unable to meet performance requirements. Requirement R2 states: “Be permitted to utilize NonConsequential Load Loss as an interim solution, which normally is not permitted for category P0 in Table 1, in for situations that are beyond the control
of the Planning Coordinator or Transmission Planner that prevent the implementation of a Corrective Action Plan in the required timeframe…” Texas
RE reads the proposed standard language as allowing the entity to determine the “required timeframe.” While the revised language provides for a
coordination process with regulatory authorities, it does not appear these entities could reject a Corrective Action Plan if the required timeframe was
unduly extended. Texas RE therefore continues to recommend placing more explicit requirements around CAP development and implementation to
prevent unilaterally lengthy CAPs and ensure their timely and effective implementation.
Likes

0

Dislikes
Response

0

3. The DT updated Attachment 1 based on comments received. Do you agree? If you do not agree, please provide your recommendation and,
if appropriate, technical or procedural justification.
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
The SDT made vast improvements to Attachment 1 by splitting MISO and SPP zones into MISO North, MISO South, SPP North, and SPP South. The
SDT attempted to move the disjointed sections of SERC Central to the appropriate MISO or SPP zones. However, the SDT needs to include
geographical boundaries to clarify which SERC Central PCs should belong to MISO North, MISO South, SPP North, and SPP South. For example:
•
•

Zone - “MISO South”
Planning Coordinator(s) – “Planning Coordinator(s) in MISO and SERC that serve portions of Montana, North Dakota, South Dakota,
Minnesota, Iowa, Wisconsin, Michigan, Indiana, Illinois, Missouri, or Kentucky”

Likes

0

Dislikes

0

Response
Adrian Andreoiu - BC Hydro and Power Authority - 1, Group Name BC Hydro
Answer

No

Document Name
Comment
B.C. has a wide geographic area, applying one common extreme temperature is not ideal. The Canada West cold benchmark event temperatures are
closer to our BC Hydro south region coldest days temperature. However, as winter peaking utilities, most of BC Hydro’s temperature sensitive load
(mostly distribution load) are located in the Lower Mainland and Vancouver Island.
BC Hydro recommends that the Canada West zone be split into BC and Alberta based on weather and geographical differences that are more
conducive to a robust ETA.

Likes

0

Dislikes

0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
Please view response to Question 1.
Likes

0

Dislikes

0

Response
Helen Lainis - Independent Electricity System Operator - 2, Group Name IRC SRC
Answer

No

Document Name
Comment
It is not clear to the IRC SRC whether the current draft addresses temperature variances from east to west of the current zones, not just north to south.
For example, entities with a wide east to west territory may have vastly different climates that may need to be split into additional zones.
During the last comment review, the drafting team discussion indicated that a Planning Coordinator with more than one zone may utilize the same
weather event. Ideally the drafting team would revert to the contiguous planning coordinator zones. Either way, this understanding, that two zones
within a single PC may use the same event, should be documented within the standard to ensure there is no ambiguity should an entity carry out such
approach. The IRC SRC would like to see clarification in the language that indicates regions are allowed to utilize the same scenario provided it meets
the requirements in 2.1 and 2.2.
ERCOT, IESO, and PJM abstain from IRC SRC response and comments to Q3.
Likes

0

Dislikes

0

Response
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer

No

Document Name
Comment
SPP’s PC footprint should not be split into northern and southern zones (see question #1).
Likes
Dislikes

0
0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
Comment
FirstEnergy has no concerns with the update to Attachment 1.
Likes

0

Dislikes

0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
In the attachment 1, remove “WECC” from “WECC Southwest” to match up with the Zones Map.
Likes

0

Dislikes
Response

0

Sharon Darwin - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Southern Company supports EEI’s comments.
Likes

0

Dislikes

0

Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

Yes

Document Name
Comment
ITC supports the proposed changes made to Attachment 1 zones.
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 made to Attachment 1.
Likes

0

Dislikes

0

Response
Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer

Yes

Document Name
Comment
PNM & TNMP agrees with the changes to Attachment 1.
Likes

0

Dislikes

0

Response
Daniel Gacek - Exelon - 1, Group Name Exelon
Answer

Yes

Document Name
Comment
Exelon agrees with the updates made to the table and map in Attachment 1.
Likes

0

Dislikes

0

Response
Greg Sorenson - Greg Sorenson On Behalf of: Tremayne Brown, ReliabilityFirst , 10; - Greg Sorenson
Answer

Yes

Document Name
Comment
There may be only limited value is running dynamic analysis on a Long-Term planning case (i.e. 10 yr out case). And these cases are difficult to build
and are often not N-1 secure (meaning not all single contingencies will result in a valid load flow solution). Given this, and the multiple future
assumptions, the dynamic portion of the studies may not provide tangible value.”
Likes

0

Dislikes

0

Response
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer
Document Name

Yes

Comment
Ameren agrees with EEI's comments.
Likes

0

Dislikes

0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
None.
Likes

0

Dislikes

0

Response
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer

Yes

Document Name
Comment
See EEI Comments
Likes

0

Dislikes

0

Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment

Yes

See EEI Comments
Likes

0

Dislikes

0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

Yes

Document Name

Draft 4 Attachment 1 Example.pdf

Comment
The Attachment 1 graphic would greatly benefit from including state boundaries. Please see attached example.
Draft 4 Attachment 1 Example.pdf
Likes

0

Dislikes

0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Junji Yamaguchi, Hydro-Quebec (HQ), 1, 5; Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal
Mazza
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer
Document Name
Comment

Yes

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0

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Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

Yes

Document Name
Comment
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0

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0

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Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
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0

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0

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Nazra Gladu - Manitoba Hydro - 1
Answer

Yes

Document Name
Comment
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0

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0

Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
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0

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0

Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

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Comment
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0

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0

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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

Yes

Document Name
Comment
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0

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0

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Kevin Conway - Western Power Pool - 4
Answer
Document Name
Comment

Yes

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0

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0

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Joshua London - Eversource Energy - 1, Group Name Eversource
Answer

Yes

Document Name
Comment
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0

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0

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Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

Yes

Document Name
Comment
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0

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0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

Yes

Document Name
Comment
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0

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0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1

Answer

Yes

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Comment
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0

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0

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Richard Vendetti - NextEra Energy - 5
Answer

Yes

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Comment
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0

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0

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Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

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Comment
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0

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0

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Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

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Comment
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0

Dislikes

0

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Donald Lock - Talen Generation, LLC - 5
Answer

Yes

Document Name
Comment
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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 NPCC RSC
Answer

Yes

Document Name
Comment
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0

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0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

Yes

Document Name
Comment
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0

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0

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Carver Powers - Utility Services, Inc. - 4

Answer

Yes

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Comment
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0

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0

Response
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

Yes

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Comment
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0

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0

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Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

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Comment
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0

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0

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Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

Yes

Document Name
Comment
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0

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0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer
Document Name
Comment
Abstain
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0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10

Answer
Document Name
Comment
Texas RE continues to be concerned that multiple contingencies may not be used to assess the system in extreme temperature events. In
Requirement R7, Table 1 only shows single contingencies and double circuit contingencies for assessing steady state and stability performances.
Based on the contingencies listed in Table 1, the reasoning for R7 is not clear. Are the responsible entities expected to select single contingencies and
double circuit contingencies and use those contingencies to assess the system? During extreme temperature events, multiple overlapping
contingencies are expected and frequently occur. Given this fact, the proposed standard should correspondingly require Registered entities to study
overlapping contingencies to identify system deficiencies and prepare the mitigation plans.
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0

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Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Document Name
Comment
During the last comment review, the drafting team discussion indicated that a Planning Coordinator with more than one zone may utilize the same
weather event. This understanding should be documented within the standard to ensure there is no ambiguity should an entity conduct such an
approach. The MRO-NSRF would like to see clarification in the language that indicates regions are allowed to utilize the same scenario provided it
meets the requirements in 2.1 and 2.2.
Likes

1

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Response

Scott Brame, N/A, Brame Scott
0

4. The DT believes proposed modifications in TPL-008-1 provide entities with flexibility to meet the reliability objectives in a cost-effective
manner. Do you agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost-effective approaches,
please provide your recommendation and, if appropriate, technical or procedural justification.
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

No

Document Name
Comment
Sensitivity to generation, load and transfers are already studied as part of TPL-001-5.1 yearly for near and long-term scenarios (year 10/year 12). The
sensitivity additional studies proposed for R8.2 are unlikely to yield any new information and will be duplicative work for Transmission Planners.
The Extreme Temperature Assessment is already a very extreme sensitivity study itself that should already capture modified load, generation,
transmission, and transfers befitting this analysis per R3, so it is not needed nor appropriate to study sensitivities for sensitivity cases. Further sensitivity
cases to adjust such power flow variables would be a nice idea, but it does not appear cost effective to mandate developing and evaluating “sensitivity”
cases in addition to the already sensitive nature if the extreme weather assessment.
If sensitivity cases are deemed necessary, it would be more cost-effective to waive the obligation to study and analyze stability for those sensitivities.
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0

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0

Response
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer

No

Document Name
Comment
The changes to the zoning and mapping create an administrative burden with little benefit to the reliability based upon the current language. This
requires coordination with ourselves and the proposed event library recommends the same across our entire footprint. This would not be cost effective
to create multiple models and sensitivities which would not leverage the transmission system built to support reliability.
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0

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0

Response
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CEHE believes the new draft TPL-008-1 still imposes a cost and time burden to PCs/TPs without substantial benefits to reliability of BPS. To support
this standard CEHE would like to learn more information on any economic analysis that was performed.
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0

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Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
See our comments for Question 1.
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Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

No

Document Name
Comment
•
•

Likes

ITC believes it is not cost effective to build sensitivity models and analyze the required events yet not require any Corrective Action Plans. If
these cases have value and justification to be created and analyzed, then the problems generated within them are also justified to need
mitigation to assure reliability.
Corrective Action plans utilizing only Non Consequential Load Loss do not provide value regarding reliability objectives. Reliability should aim to
maintain service to serve firm load and for single contingencies when it may be critical to end users/load under extreme temperature conditions.
Entities would need to proactively start shedding load for changes in generation, real and reactive forecasted Load, or transfers; load shed is
not a solution to the problems identified on how to deliver reliable service to load.
0

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Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford

Answer

No

Document Name
Comment
The attempt for flexibility is appreciated but this standard still falls short of something that is clear and allows the PC/TP to appropriately plan to meet
reliability goals during extreme temperature events. The inclusion of outside entity reviews of CAPs offers the reviewer flexibility as there are no bounds
provided to them. The PC/TP, however, is potentially impacted by subjective reviews that have no framework with which the PC/TP can effectively
respond.
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0

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0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

No

Document Name
Comment
New Standard requiring extensive coordination with adjacent PCs/TPs within the defined “zones”. New Standards impose a cost and time burden to
PCs/TPs without necessarily providing substantial benefits to the reliability of the BPS.
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0

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Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

No

Document Name
Comment
This should be part of TPL-001 and not a separate TPL Standard.
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0

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0

Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC

Answer

No

Document Name
Comment
At this time, we are unable to fully agree that this standard provides the necessary flexibility to meet the reliability objectives in a cost-effective
manner. We would be interested in more information on any economic analysis that was performed.
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0

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Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
Comment
FirstEnergy has no concerns with the cost-effectiveness of this draft.
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0

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0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
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0

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0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Document Name

Yes

Comment
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0

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0

Response
Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
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0

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0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
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 NPCC RSC
Answer

Yes

Document Name
Comment
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0

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0

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Daniel Gacek - Exelon - 1, Group Name Exelon
Answer

Yes

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Comment
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0

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0

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Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer

Yes

Document Name
Comment
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0

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0

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Mike Magruder - Avista - Avista Corporation - 1
Answer
Document Name

Yes

Comment
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0

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0

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Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

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Comment
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0

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0

Response
Sharon Darwin - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

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Comment
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0

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0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

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Comment
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0

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Response

0

Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

Yes

Document Name
Comment
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0

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0

Response
Kevin Conway - Western Power Pool - 4
Answer

Yes

Document Name
Comment
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0

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0

Response
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
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0

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0

Response
Nazra Gladu - Manitoba Hydro - 1
Answer
Document Name
Comment

Yes

Likes

0

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0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

Yes

Document Name
Comment
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0

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0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 3,
6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; - Tim
Kelley, Group Name SMUD and BANC
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Junji Yamaguchi, Hydro-Quebec (HQ), 1, 5; Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal
Mazza
Answer

Yes

Document Name
Comment
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0

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0

Response
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Document Name
Comment
NV Energy does not have a comment regarding the cost-effectiveness.
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0

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0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
Duke Energy’s focus is on system reliability and will not respond to the cost effectiveness question.
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0

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0

Response
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop

Answer
Document Name
Comment
Ameren prefers not to comment on the cost effectiveness of the project.
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0

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0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
Document Name
Comment
Black Hills Corporation will not comment on cost effectiveness.
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0

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0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer
Document Name
Comment
Abstain
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0

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Response

0

5. Provide any additional comments for the drafting team to consider, including the provided technical rationale document, if desired.
Chantal Mazza - Chantal Mazza On Behalf of: Junji Yamaguchi, Hydro-Quebec (HQ), 1, 5; Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; - Chantal
Mazza
Answer
Document Name
Comment
HQ supports these revisions.
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0

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0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer
Document Name
Comment
Requirement R10 should explicitly clarify that a Corrective Action Plan is not required for P7 Contingencies, as stated in the previous draft 2, Table 2.1,
page 11.
R6 VRF is 'High', but it should be set as ‘Medium’ to match TPL-008 R5.
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0

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0

Response
Thomas Foltz - AEP - 5
Answer
Document Name
Comment
AEP offers the following additional comments regarding potential overlapping or duplicative obligations.
R3 and R4 appear duplicative in that they both involve the formation of study cases. R3 states “Implement a process for developing benchmark
planning cases” while R4 states “Use the coordination process… to develop the following… planning benchmark cases.” R1’s “shall complete its
responsibilities such that the … assessment is completed…” appears duplicative with R8’s “shall complete steady-state and stability analysis… ”. AEP

recommends removing the last sentence from R1 regarding completing the Extreme Temperature Assessment at least once every five calendar years
and appending it to R8.
Regarding R5, the TP and PC should already possess steady state voltage criteria to satisfy TPL-001 R5. As a result, AEP recommends removing R5
to avoid compliance risk associated with duplicative obligations. If the drafting team chooses to retain R5, the phrase “shall have criteria for acceptable
System steady state voltage limits and post-Contingency voltage deviations” might benefit from something more actionable than “shall have.” AEP
recommends the drafting team consider “shall devise” or “shall develop.”
R6’s identification of instability, uncontrolled separation, and cascading per criteria or methodology is already required in TPL-001 R6, which once again
appears duplicative and would unnecessarily increase compliance risk. AEP recommends it be removed.
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Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
Document Name
Comment
The below comment was provided previously for R2.
NERC's consultant uses BA load weighting (based on notes and conversations provided in the 9/10 TPL-008 presentation). As a result, this weighting
practice does not appear to directly meet this proposed R2.2 language regarding the most extreme events for a region. The temperature may not
actually be representative of “across the zone” because of this weighting. Of reliability considerations, load is certainly part of the need, but potential
impacts to generation and the connecting transmission, which may be in other regions, are also important pieces to the delivery of resource to load.
Removal or modification of this R2 ‘most extreme’ language is recommended; or exempting the NERC library from needing to follow these criteria.
Alternately, the SDT may modify to allow weighting to be used in method.
Because the NERC Extreme Weather Event library is only updated every 3 years in the current plan, it is possible that an event in the library would
contain events that would not meet these R2 criteria for event “freshness”. The SDT may wish to consider modifying the language regarding time, or an
additional clause, to permit events currently in the NERC Extreme Weather Event library to not be subject to the selection criteria currently in R2, or that
entities may use the other criteria to evaluate and select other events.
The below comment was provided previously for R3-R4.
In FERC Order 896, paragraph 39, there is a Commission Determination as follows:
“We also direct NERC to include in the Reliability Standard the framework and criteria that responsible entities shall use to develop from the relevant
benchmark event planning cases to represent potential weather-related contingencies (e.g., concurrent/correlated generation and transmission outages,
derates) and expected future conditions of the system such as changes in load, transfers, and generation resource mix, and impacts on generators
sensitive to extreme heat or cold, due to the weather conditions indicated in the benchmark events. Developing such a framework would provide a
common design basis for responsible entities to follow when creating benchmark planning cases. This would not only help establish a clear set of
expectations for responsible entities to follow when developing benchmark planning events, but also facilitate auditing and enforcement of the
Standard.”

In review of Order 896, we find the term “contingencies” is used two different ways. Paragraph 39 describes things that are in the base or N-0 state – for
example, a cold weather event occurs, and certain wind generators can no longer operate – this as a base contingency. Similarly, in paragraph 88,
there is an additional Commission Determination as follows, in further support of these baseline “contingency” outages:
“Pursuant to section 215(d)(5) of the FPA, we adopt the NOPR proposal and direct NERC to require under the new or revised Reliability Standard the
study of concurrent/correlated generator and transmission outages due to extreme heat and cold events in benchmark events as described in more
detail below.”
Then later, in Paragraph 92 (still under the Commission Determination), FERC further clarifies:
“Regarding the comments of NYISO and EPRI on the difference between extreme events and contingencies covered under Reliability Standard TPL001-5.1, we clarify that all contingencies included in benchmark planning cases under the new or modified Reliability Standard will represent initial
conditions for extreme weather event planning and analysis. These contingencies (i.e., correlated/concurrent, temperature sensitive outages, and
derates) shall be identified based on similar contingencies that occurred in recent extreme weather events or expected to occur in future forecasted
events.”
From these, it is clear that Order 896 is expecting “contingencies” of weather-based equipment outages to be part of the base or N-0 system state. The
more traditional “contingencies” are then addressed on top of this condition, as presented in Order 896, Section G, starting at Paragraph 95.
The specific request from this comment is for the SDT to clarify how it expects such base “contingencies” to be included in the model. There does not
appear to be language currently in the standard in support of this, and it is clear from Order 896 that it is expected both the base model outage
“contingencies” and then subsequent contingency events to test system performance.
The SDT responded to this in its version 3 comment response:
“The SDT drafted Requirement R4 to require the responsible entity to use data consistent with Reliability Standard MOD-032, supplemented by other
sources as needed, for developing benchmark planning cases that represent System conditions based on selected benchmark temperature events.
This aligns with directives in FERC Order No. 896, paragraph 30, emphasizing the requirement of developing both benchmark planning cases and
sensitivity study cases. Requirement R4 is consistent with Reliability Standard TPL-001-5.1 in cross-referencing Reliability Standard MOD-032, which
establishes consistent modeling data requirements and reporting procedures for the development of planning horizon cases necessary to support
analysis of the reliability of the interconnected System. It is also consistent with Reliability Standard TPL-001-5.1 in acknowledging that data from other
sources may be required to supplement the data collected through Reliability Standard MOD-032 procedures.”
The original comment was not related at all to MOD-032 data. FERC is expecting NERC to develop a standard to build extreme weather cases, and as
part of those cases, FERC is requiring that in the base N-0 condition also include “weather-related contingencies (e.g., concurrent/correlated generation
and transmission outages, derates)”. The current draft of TPL-008 does not mention outages, de-rates, or generator availability due to extreme weather
in its R3 or R4 language. R3.2 simply includes “Forecasted seasonal and temperature dependent adjustments for Load, generation, Transmission, and
transfers within the zone.” And R3.3 similar “Assumed seasonal and temperature dependent adjustments for Load, generation, Transmission, and
transfers in areas outside the zone, as needed.”, but language for “weather-related contingencies (e.g., concurrent/correlated generation and
transmission outages, derates)” from Order 896 is absent from the standard in its current form. This language should be added, likely to R3.2 and R3.3
because it conveys powerful root concept of unexpected equipment outages and limitations in the base state due to extreme weather. If it is the SDT’s
intention that entities will review Order 896 and conclude that such concurrent outages are to be covered by a ‘supplemented by other sources as
needed’ clause, this is not the case. The standard needs to include language for entities to consider how such extreme weather related
concurrent/correlated outages are to be included in the base case.
The below comment was provided previously for R9.
In Order 896, FERC’s Commission determination in paragraph 157 reads:
“As stated above, we adopt and modify the NOPR proposal and direct NERC to require in the new or modified Reliability Standard the development of
corrective action plans that include mitigation for specified instances where performance requirements for extreme heat and cold events are not met—
i.e., when certain studies conducted under the Standard show that an extreme heat or cold event would result in cascading outages, uncontrolled
separation, or instability.”

FERC’s directive is when the outcome of studies would result in cascading outages, uncontrolled separation, or instability, a corrective action plan is
required. However, in TPL-008, the SDT has gone further. The current state of draft TPL-001-8 R9 states:
“Each responsible entity, as identified in Requirement R1, shall develop a Corrective Action Plan(s) when the analysis of a benchmark planning case, in
accordance with Requirement R8 Part 8.1, indicates its portion of the Bulk Electric System is unable to meet performance requirements for category P0
or P1 in Table 1. For each Corrective Action Plan, the responsible entity shall:”
The difference here is Order 896 is only requiring corrective action plans for cascading outages, uncontrolled separation, or instability. the SDT is
proposing to require corrective action plans for not meeting performance criteria, which also includes normal voltage limits or normal line ratings, even
though these exceedances may not result in cascading outages, uncontrolled separation, or instability. The request is for the SDT to align its R9
language with Order 896 paragraph 157 language. These other limits are needed to assess for cascading outages, uncontrolled separation, or
instability, but the requirement to develop a corrective action plan for such exceedances is beyond Order 896’s request for this proposed standard.
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Response
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
BPA understands the complexities of drafting technically sound standards and appreciates the SDT's efforts through the multiple postings of this
project.
Likes

0

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0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer
Document Name
Comment
No Comment
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0

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0

Kevin Conway - Western Power Pool - 4
Answer
Document Name
Comment
The Western Power Pool would like to thank the Drafting Team for working hard to find consensus. We understand the challenges the Drafting Team
faces in meeting the expectations of a number of different organzations across North America.
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0

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0

Response
Joshua London - Eversource Energy - 1, Group Name Eversource
Answer
Document Name
Comment
Requirement 3 –

Eversource recommends reinserting “Transmission Planner” or the phrase used in R4 “Each responsible entity, as identified in Requirement R1” as
part of the coordination in R3. The DT stated in its Consideration of Comments that “Coordination is at the PC level and not at the TP level.” Eversource
agrees this to be true for developing the Temperature Events but disagrees in regards to implementing a process for developing planning cases. If the
TPs are going to be expected to have a role in completing the Extreme Temperature Assessment as stated in Requirement 1, they should participate in
implementing a process for the development of cases.
Each Planning Coordinator shall coordinate with all Planning Coordinators and Transmission Planners within each of its zone(s)…; or
Each Planning Coordinator shall coordinate with all Planning Coordinators and with each responsible entity, as identified in Requirement R1, within
each of its zone(s)…;
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0

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0

Response
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer
Document Name
Comment

None
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0

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0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Document Name
Comment
FirstEnergy has no additional comments.
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0

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0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Document Name
Comment
NA
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0

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0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE continues to underscore that the Standard Requirements, as currently stated, do not appear to require assessing the impact of concurrent
failures of the Bulk Power System generation and transmission equipment that are typically experienced during extreme heat or cold weather
conditions. FERC Order No. 896 states: “…the impact of concurrent failures of Bulk-Power System generation and transmission equipment and the

potential for cascading outages that may be caused by extreme heat and cold weather events should be studied”. The Considerations of the Order
document says “Per Requirement R4, the data necessary to build the benchmark planning cases must be provided via MOD-032 and supplemented by
other sources as needed. Any concurrent/correlated generator and transmission outages due to extreme heat and cold events in benchmark
temperature events should be reflected in the model data and thus represented in the initial conditions of the benchmark planning cases.”

Based on the current Requirements R3 and R4 language, the cases could be built with high loads and high generation dispatch for the extreme weather
without including concurrent outages. Therefore, a requirement in R3 or R4 that specifically says to include “concurrent” generator and transmission
outages in the initial conditions of the benchmark planning cases needs to be added in accordance with the FERC Order. Also, the rationale for those
concurrent outages selected for the initial conditions shall be available as supporting information. Texas RE noticed that the Technical Rationale does
mention concurrent outages and recommends incorporating this language directly into the requirement language itself through the note described
below.

Texas RE suggests either requiring the basic assumptions described in R3 to include, at minimum, the severe contingencies or outages experienced
within each Transmission Planner’s respective area during the most extreme conditions to be modeled in the benchmarking cases. Texas RE
recommends the following language for Requirement R3:
3.5 The most severe continencies experienced in each Transmission Planner’s respective area during a historical most extreme conditions shall be
documented and modeled in the benchmark planning case(s).
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Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer
Document Name
Comment
Comments: GTC has provided the below recommendations in previous ballots, however, it appears that the SDT has not considered revising the
proposed standard to address, therefore, these concerns/recommendations are still considered valid by GTC.
R4:
• The SDT should consider removing R4.2, since the assessment already covers multiple extreme weather scenarios. There is questionable
reliability benefit in running additional sensitivities that do not rise to the level of requiring (or eliminating) corrective actions.
R5:
• The recently adopted NERC Glossary term, System Voltage Limits, should be referenced in this requirement instead of the outdated wording
“System steady state voltage limits”. “…shall have criteria for acceptable System Voltage Limits …”
• Since this requirement appears to refer to steady-state voltage, the post contingency voltage deviation portion of the existing requirement should
be removed. The resultant steady-state voltage level being outside of acceptable high and low limits is the point of concern. For example, if a low

voltage criterion is 0.92 p.u., then voltages below this limit would violate this particular criterion regardless of whether the beginning voltage was 0.95
p.u., 0.98 p.u., or any other voltage level.
R6:
• The inclusion of “within an Interconnection” is not appropriate as the PC or TP should not be required to assess outside of its applicable area.
Note the inclusion of more appropriate language referring to the PC’s or TP’s planning area (its portion of the Bulk Electric System) in this draft so it is
not clear why some requirements refer to an Interconnection while others, more correctly, refer to the area of actual responsibility for the PC or TP.
• The following bullet contains a wording addition to clarify the applicability of this requirement to System-wide impacts. This is also consistent with
wording in other Reliability Standards when referencing these types of impacts.
• “Each responsible entity, as identified in Requirement R1, shall define and document the criteria or methodology used in the Extreme
Temperature Assessment analysis to identify instability, uncontrolled separation, or Cascading of the Bulk Electric System.”
R8:
• It is unclear if the responsible entity must identify continencies for each event type shown within each category, or only those event types that are
expected to produce more severe System impacts on its portion of the Bulk Electric System
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Response
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Document Name

2023-07_Unofficial_Comment_Form Draft_4_110724_MRO.docx

Comment
Requirement R3 indicates forecasting Load, generation, and Transmission. There are significant barriers to modeling Load and generation based upon
temperatures, notably forecasting out into the long-term planning timeframes. With that said, the MRO NSRF recommends that the NERC and drafting
team develop implementation guidance and/or a reliability guideline to ensure Planning Coordinators can meet the requirements in the R3 section.
Several terms in the TPL-008-1 ERO Benchmark Weather Event Development and Maintenance Process DRAFT indicated defined terms are located in
the glossary of terms, yet these terms are not defined in the glossary of terms. The term Zoneal is used rather than the term Zonal. There are also
acronyms that do not represent the words spelled, for example it lists Affected Zonal Entity as ARE rather than the more representative term AZE.

Definitions Refer to the NERC Glossary of Terms3 for the below capitalized terms used in this process.
• Affected Zoneal Entity (ARE)
• Compliance Enforcement Authority (CEA)
• Coordinated Oversight
• Extreme Temperature Assessment (ETA)

• Lead Zoneal Entity (LRE)
• Multi-Zone Registered Entity (MRRE)
Likes

1

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Scott Brame, N/A, Brame Scott
0

Response
Adrian Andreoiu - BC Hydro and Power Authority - 1, Group Name BC Hydro
Answer
Document Name
Comment
1. Requirement R1 as drafted includes two separate requirements, i.e. to (1) identify responsibilities amongst applicable PCs and TPs, and (2) complete
an Extreme Temperature Assessment every five years.
BC Hydro suggests that these are separate objectives and recommends that this Requirement be split to reflect these accordingly for enforceability (e.g.
incident severity level), and cause-based incident monitoring.
2. BC Hydro’s understanding is that in order to determine the Contingencies that have a more severe impact per R7, the ETA needs to account for all
contingencies within the identified zone(s), and not just those within its portion of the BES. Please confirm or provide additional clarity as appropriate.
3. Requirement R4 and the associated VSL Levels reference “the coordination process developed in Requirement R3”. R3 requires a benchmark
planning cases development process, it does not require a coordination process.
BC Hydro recommends Recommend revising R4 and the associated VSL Levels for clarity and consistency.
BC Hydro also recommends that the language of R3 be revised to read “to implement a documented process” rather than “to implement a process”.
4. The VSL Table for Requirement R1 indicates a Severe Level if an entity “failed to identify individual and joint responsibilities”. There are no other
Severity Levels associated with responsibilities identification, which is conducive to an interpretation that failing to identify even one of the R2 through
R11 associated responsibility would be classified as a Severe VSL. BC Hydro suggests that failing to identify one or less than the full set of
responsibility should carry less Severity Levels, and recommends that this be reflected in the lower Severity Levels as well.
5. The High and Severe VSL Levels for Requirement R8 are based on an entity’s failing to evaluate the results of the sensitivity (High VSL) and
benchmarking cases (Severe VSL). R8 and its associated M8 do not explicitly require that an evaluation be also retained as evidence of compliance, in
addition to the results documentation.
BC Hydro recommends that the R8, M8 and corresponding VSL Levels be revised for consistency.
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Response
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin

Answer
Document Name
Comment
•

•

•

•
•

ITC believes that the Yes for NCLL for P0 Sensitivity Cases should be changed to No. If it is deemed important to analyze a sensitivity case,
the system should be able to serve firm load both for system normal and for single contingencies. With the requirements left as proposed,
entities would need to proactively start shedding load for changes in generation, real and reactive forecasted Load, or transfers. System
Operators will be forced to rely on preventative load shed during long term construction outages when experiencing extreme weather as it is
highly likely that these will not be able to be cancelled.
ITC believes that the Yes allowing for NCLL for P1 Base and Sensitivity Cases should be changed to No. ITC believes that a reliable system
should be able to serve firm load for system normal and for single contingencies. Utilities typically schedule long term construction outages
during winter (off-peak) and then experience extreme temperature scenarios. System Operators will need to rely on preventative load shed
during these long term construction outages, that could not be cancelled if entities include NCLL as part of their corrective action plan.
ITC suggests that Footnote 6 (Page 12) include a clarification that Non Consequential Load Loss shall not be the only element in a
Corrective Action Plan. See below:
o Benchmark planning cases require the development of a Corrective Action Plan when the responsible entity’s portion of the BES is
unable to meet the performance requirements for categories P0 or P1. Additionally, in benchmark planning cases, Non-Consequential
Load Loss is not permitted for category P0 and Non Consequential Load Loss shall not be the only element of a Corrective
Action Plan unless approved by applicable regulatory authorities or governing bodies responsible for retail electric service
issues. See Requirement R9 for the relevant requirements.
Specify if temperature is F or C on benchmark table of events. Clarify and specify timing on standard on when they will review the benchmark
events.
In DRAFT ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance Standards Development and
Engineering Process Document October 2024, ITC suggests moving footnote 4 page 2 into the Process Overview and clarify if these actions
will happen every cycle, or just the first iteration.

Likes

0

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0

Response
Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer
Document Name
Comment
No additional comments.
Likes

0

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0

Response
Daniel Gacek - Exelon - 1, Group Name Exelon
Answer

Document Name
Comment
Below are a few additional comments or questions for the drafting team to consider:
1. Clarify what “long-term transmission planning horizon” is in Requirement 3.1, which is the target time horizon for this standard. Currently NERC
definition indicates year 6-10 or beyond. From our understanding, our PC intends to align with LTRTP.
2. Based on our interpretation, a benchmark temperature event doesn’t have to be a historical event. Is that correct?

Likes

0

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0

Response
Greg Sorenson - Greg Sorenson On Behalf of: Tremayne Brown, ReliabilityFirst , 10; - Greg Sorenson
Answer
Document Name
Comment
RF appreciates the efforts of the Standards Drafting Team to apply comments recieved.
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 NPCC RSC
Answer
Document Name
Comment
NPCC RSC agrees with the changes proposed by the standard drafting team.
Likes

0

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Response

0

Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
None.
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0

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0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3, 5, 1, 6;
Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Midwest Reliability Organization's NERC Standards Review Forum (MRO
NSRF) on question 5
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0

Response
Helen Lainis - Independent Electricity System Operator - 2, Group Name IRC SRC
Answer
Document Name
Comment
The IRC SRC is concerned that Requirement R3 unnecessarily and inadvertently limits the ability of entities to properly develop their benchmark
planning cases. Specifically, the IRC SRC is concerned that R3 could be understood to mean that entities are limited to making the adjustments
specifically described in R3 and are prevented from making adjustments necessary to ensure that the generation necessary to serve load is available so
that the case can solve. As the drafting team recognizes in the Technical Rationale, adjusting the case to ensure that it contains enough generation to
serve the modeled load is essential to ensure that the standard does not stray into the realm of resource adequacy issues and fully complies with
paragraph 94 of FERC Order No. 896, which states that resource adequacy is not in scope for this project. While the IRC SRC appreciates this
recognition, the Technical Rationale is not a binding document, and future revisions to the standard may introduce additional ambiguity regarding what
types of adjustments are permissible under Requirement R3.

To clarify the standard and better position it for future revisions, the IRC SRC recommends that the drafting team revise Part 3.2 by replacing the period
at the end of Part 3.2 with the following: “, provided that the responsible entity may adjust the total modeled generation or Load in each case as
necessary to allow the total modeled generation to serve the total modeled System Load.”
The IRC SRC also recommends that Requirement R4 be revised as needed to align with any revisions made to Requirement R3.
In addition, the IRC SRC requests that the ERO develop a Reliability Guideline for this proposed standard, and in particular, for Requirement R3
showing how a Planning Coordinator would adjust the benchmark planning case to ensure that it contains enough generation necessary to serve load.
Likes

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Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment
ERCOT joins the comments submitted by the IRC SRC for this question and adopts them as its own.
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Response
Gregory Campoli - New York Independent System Operator - 2
Answer
Document Name
Comment
The NYISO would like to confirm that is it acceptable to use additional (beyond those directed in Requirement 2) weather metrics to identify the
benchmark temperature events. For example, summer extreme conditions could include a temperature-humidity index which integrates temperature
and humidity and is shown to be a more robust predictor of peak loads than temperature alone. Likewise, winter extreme conditions could include a
wind component (i.e., a wind-chill index). In either case, the associated temperature value could easily be extracted, as necessary, for any follow-on
analysis (e.g., line ratings) requiring temperature specifically.
The NYISO would like to confirm that is it acceptable to use additional (beyond those directed in Requirement 2) averaging mechanisms which have
been demonstrated to be robust predicators of extreme peak loads. For example, the NYISO currently employs a three-day weighted average
temperature index for summer conditions and a three-day weighted average of a temperature-wind index variable for winter conditions.
The NYISO would like to confirm that is it acceptable to leverage their own knowledge and expertise in constructing the specific extreme heat and cold
temperature events to be studied, within reasonable constraints, such as the 40-year historic period.

Likes

0

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0

Response
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group Name
SPP RTO
Answer
Document Name
Comment
Another concern for SPP is applicable to the model not being able to solve which includes the sensitivity (stability cases for P0 condition). It is unclear
on the expectation of the drafting team in reference to the PC not being able to solve the models for the various categories of the ETA. Also, there are
concerns around gathering and aligning the appropriate temperature data independently.
Requirement R3 indicates forecasting Load, generation, and Transmission. There are significant barriers to modeling Load and generation based upon
temperatures, notably forecasting out into the long-term planning timeframes. With that said, SPP recommends that the NERC and drafting team
develop implementation guidance and/or a reliability guideline to ensure Planning Coordinators are able to meet the requirements in the R3 section.
Likes

0

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0

Response
Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer
Document Name
Comment
Thank you for the opportunity to comment.
Likes

0

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0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric Company,
3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
Document Name
Comment

The DT should highly consider or leave it to Planning Coordinator’s discretion when it comes to sensitivities: PC’s should be given the
opportunity/flexibility in determining whether sensitivities are needed or as to how much study is needed regarding sensitivities.
Likes

0

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0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments.
Likes

0

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0

Response
Amy Wilke - American Transmission Company, LLC - 1
Answer
Document Name
Comment
While ATC has voted in support of approving project 2023-07; we are also in support of the comments provided by the MRO NSRF.
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Consideration of Comments
Project Name:

2023-07 Transmission Planning Performance Requirements for Extreme Weather | Draft 4

Comment Period Start Date: 11/7/2024
Comment Period End Date: 11/21/2024
Associated Ballot(s):

2023-07 Transmission Planning Performance Requirements for Extreme Weather Implementation
Plan AB 4 OT
2023-07 Transmission Planning Performance Requirements for Extreme Weather TPL-008-1 AB 4
ST

There were 50 sets of responses, including comments from approximately 140 different people from approximately 89
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, 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, contact Director, Standards Development Jamie Calderon (via email) or at
(404) 446-9647.

RELIABILITY | RESILIENCE | SECURITY

Questions
1. The Drafting Team (DT) updated Requirement R2 based on comments received. Do you agree? If you do not agree, please provide
your recommendation and, if appropriate, technical or procedural justification.
2. The DT updated Requirement R9 based on comments received. Do you agree? If you do not agree, please provide your
recommendation and, if appropriate, technical or procedural justification.
3. The DT updated Attachment 1 based on comments received. Do you agree? If you do not agree, please provide your
recommendation and, if appropriate, technical or procedural justification.
4. The DT believes proposed modifications in TPL-008-1 provide entities with flexibility to meet the reliability objectives in a costeffective manner. Do you agree? If you do not agree, or if you agree but have suggestions for improvement to enable more costeffective approaches, please provide your recommendation and, if appropriate, technical or procedural justification.
5. Provide any additional comments for the drafting team to consider, including the provided technical rationale document, if desired.

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

2

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 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

3

Organization
Name
BC Hydro
and Power
Authority

MRO

Name

Adrian
Andreoiu

Anna
Martinson

Segment(s)

1

1,2,3,4,5,6

Region

WECC

MRO

Group Name Group Member
Name
BC Hydro

Group
Member
Organization

Group
Group Member
Member
Region
Segment(s)

Hootan Jarollahi BC Hydro and 3
Power
Authority

WECC

Helen Hamilton BC Hydro and 5
Harding
Power
Authority

WECC

Adrian Andreoiu BC Hydro and 1
Power
Authority

WECC

MRO Group Shonda McCain Omaha Public 1,3,5,6
Power District
(OPPD)
Michael
Brytowski

1,3,5,6

MRO

Jamison Cawley Nebraska
Public Power
District

1,3,5

MRO

Jay Sethi

1,3,5,6

MRO

Husam Al-Hadidi Manitoba
1,3,5,6
Hydro (System
Performance)

MRO

Kimberly
Bentley

MRO

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

Great River
Energy

MRO

Manitoba
Hydro (MH)

Western Area 1,6
Power
Administration

4

Jaimin Patal

Saskatchewan 1
Power
Corporation
(SPC)

MRO

George Brown

Pattern
Operators LP

5

MRO

Larry Heckert

Alliant Energy 4
(ALTE)

MRO

Terry Harbour

MidAmerican 1,3
Energy
Company
(MEC)

MRO

Dane Rogers

Oklahoma Gas 1,3,5,6
and Electric
(OG&E)

MRO

Seth Shoemaker Muscatine
Power &
Water

1,3,5,6

MRO

Michael Ayotte

ITC Holdings

1

MRO

Andrew Coffelt

Board of
Public
UtilitiesKansas (BPU)

1,3,5,6

MRO

Peter Brown

Invenergy

5,6

MRO

Angela Wheat

Southwestern 1
Power
Administration

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

MRO

5

Exelon

Daniel Gacek 1

Independent Helen Lainis
Electricity
System
Operator

Eversource
Energy

Joshua
London

2

1

Public Utility Joyce Gundry 3
District No. 1
of Chelan
County

Exelon
IRC SRC

Eversource

CHPD

Joshua Phillips

Southwest
Power Pool

2

MRO

Patrick Tuttle

Oklahoma
Municipal
Power
Authority

4,5

MRO

Daniel Gacek

Exelon

1

RF

Kinte Whitehead Exelon

3

RF

Bobbi Welch

Midcontinent 2
ISO, Inc.

MRO

Gregory Campoli New York
Independent
System
Operator

2

NPCC

Helen Lainis

IESO

2

NPCC

Charles Yeung

SPP

2

SERC

Elizabeth Davis

PJM

2

RF

Joshua London

Eversource
Energy

1

NPCC

Vicki O'Leary

Eversource
Energy

3

NPCC

Rebecca Zahler

Public Utility
District No. 1
of Chelan
County

5

WECC

Joyce Gundry

Public Utility
District No. 1

3

WECC

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

6

of Chelan
County
Diane Landry

FirstEnergy - Mark Garza
FirstEnergy
Corporation

4

FE Voter

Public Utility
District No. 1
of Chelan
County

1

WECC

Tamarra Hardie Public Utility
District No. 1
of Chelan
County

6

WECC

Julie Severino

FirstEnergy FirstEnergy
Corporation

1

RF

Aaron
Ghodooshim

FirstEnergy FirstEnergy
Corporation

3

RF

Robert Loy

FirstEnergy FirstEnergy
Solutions

5

RF

Mark Garza

FirstEnergyFirstEnergy

1,3,4,5,6

RF

6

RF

Black Hills
Corporation

1

WECC

Black Hills
Corporation

3

WECC

Stacey Sheehan FirstEnergy FirstEnergy
Corporation
Black Hills
Rachel
Corporation Schuldt

6

Black Hills
Travis
Corporation - Grablander
All Segments Josh Combs

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

7

Northeast
Ruida Shu
Power
Coordinating
Council

1,2,3,4,5,6,7,8,9,10 NPCC

NPCC RSC

Rachel Schuldt

Black Hills
Corporation

6

WECC

Carly Miller

Black Hills
Corporation

5

WECC

Sheila Suurmeier Black Hills
Corporation

5

WECC

Gerry Dunbar

Northeast
Power
Coordinating
Council

10

NPCC

Deidre Altobell

Con Edison

1

NPCC

Michele Tondalo United
Illuminating
Co.

1

NPCC

Stephanie Ullah- Orange and
Mazzuca
Rockland

1

NPCC

Michael
Ridolfino

Central
1
Hudson Gas &
Electric Corp.

NPCC

Randy Buswell

Vermont
1
Electric Power
Company

NPCC

James Grant

NYISO

2

NPCC

Dermot Smyth

Con Ed Consolidated
Edison Co. of
New York

1

NPCC

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

8

David Burke

Orange and
Rockland

3

NPCC

Peter Yost

Con Ed Consolidated
Edison Co. of
New York

3

NPCC

Salvatore
Spagnolo

New York
Power
Authority

1

NPCC

Sean Bodkin

Dominion Dominion
Resources,
Inc.

6

NPCC

Silvia Mitchell

NextEra
1
Energy Florida Power
and Light Co.

NPCC

Sean Cavote

PSEG

4

NPCC

Jason Chandler

Con Edison

5

NPCC

Tracy MacNicoll Utility Services 5

NPCC

Shivaz Chopra

New York
Power
Authority

6

NPCC

Vijay Puran

New York
6
State
Department of
Public Service

NPCC

David Kiguel

Independent

NPCC

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

7

9

Shannon
Mickens

Shannon
Mickens

MRO,SPP
RE,WECC

SPP RTO

Joel Charlebois

AESI

7

NPCC

Joshua London

Eversource
Energy

1

NPCC

Jeffrey Streifling NB Power
Corporation

1,4,10

NPCC

Joel Charlebois

AESI

7

NPCC

John Hastings

National Grid 1

NPCC

Erin Wilson

NB Power

1

NPCC

James Grant

NYISO

2

NPCC

Michael
Couchesne

ISO-NE

2

NPCC

Kurtis Chong

IESO

2

NPCC

Michele Pagano Con Edison

4

NPCC

Bendong Sun

4

NPCC

Carvers Powers Utility Services 5

NPCC

Wes Yeomans

NYSRC

7

NPCC

Shannon
Mickens

Southwest
Power Pool
Inc.

2

MRO

Mia Wilson

Southwest
Power Pool
Inc.

2

MRO

Eddie Watson

Southwest
Power Pool
Inc.

2

MRO

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

Bruce Power

10

Erin Cullum

Tim Kelley

Tim Kelley

WECC

SMUD and
BANC

Southwest
Power Pool
Inc.

2

MRO

Jonathan Hayes Southwest
Power Pool
Inc.

2

MRO

Jeff McDiarmid

Southwest
Power Pool
Inc.

2

MRO

Scott Jordan

Southwest
2
Power Pool Inc

MRO

Mason Favazza

Southwest
2
Power Pool Inc

MRO

Zach Sabey

Southwest
2
Power Pool Inc

MRO

Josh Phillips

Southwest
Power Pool
Inc.

MRO

Nicole Looney

Sacramento
3
Municipal
Utility District

WECC

Charles Norton

Sacramento
6
Municipal
Utility District

WECC

Wei Shao

Sacramento
1
Municipal
Utility District

WECC

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

2

11

Foung Mua

Sacramento
4
Municipal
Utility District

WECC

Nicole Goi

Sacramento
5
Municipal
Utility District

WECC

Kevin Smith

Balancing
Authority of
Northern
California

WECC

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

1

12

1. The Drafting Team (DT) updated Requirement R2 based on comments received. Do you agree? If you do not agree, please provide
your recommendation and, if appropriate, technical or procedural justification.
Adrian Andreoiu - BC Hydro and Power Authority - 1, Group Name BC Hydro
Answer

No

Document Name
Comment
BC Hydro appreciates the drafting team's efforts and opportunity to comment, and offers the following comments.
(1) The ERO is not subject to TPL-008-1 regulatory compliance. Entities are relying on the ERO’s infrastructure and commitment to
maintain the benchmark temperature event library. As drafted, a PC can be in potential noncompliance if they choose to use a benchmark
event from the ERO-maintained library, and the event is not meeting the specifications per Parts 2.1 and 2.2.
BC Hydro is requesting that the drafting team in conjunction with the ERO document the controls that will be in place to maintain the
library. These controls should include the location of the library and quality checks to ensure the events in the library meet R2 Parts 2.1
and 2.2.
BC Hydro recommends revising the language of R2 Parts 2.1 and 2.2 to apply if a PC develops their own benchmark events, and not apply
to the ERO benchmark events library.
(2) A Planning Coordinator may be in a potential noncompliance if another PC is not participating in the required coordination and
assessment activities, which may be the case as different jurisdictions (such as Canada and US, or even between BC and Alberta within
Canada) have different standard adoption timelines.
BC Hydro suggests that the Implementation Plan include provisions that allow for compliance enforcement only when TPL-008-1 is
effective in all applicable jurisdictions.
Alternatively, the Canada West zone should be split into a BC-only zone. This may help alleviate compliance risks and it will also help
creating a more robust ETA given the different geographic areas and weather zones across the Canadian provinces of BC and Alberta.

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There could also be a scenario where in a multiple PC zone there may be one PC that does not participate in the coordination, or there is
no agreement on a common event. In such a scenario, all PCs may be found in noncompliance.
BC Hydro recommends that the standard include provisions to allow for conflict resolution.
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Response
Thank you for your comments.
1. Flexibility has been provided for entities who wish to develop, in coordination with other Planning Coordinators within its zone, its
own benchmark events. Additionally, the ERO has developed a process to follow to provide updated data every five years and is
committed to providing this for entities. The data developed by the ERO followed the criteria in Parts 2.1 and 2.2 and an entity
would pull the information provided in the library to show compliance for the 40 worst and 20 extreme.
A link has been added to the ERO Benchmark Event Library under the Associated Documents section for the location of the library.
The team feels benchmark events are clear in the standard and can be completed by the ERO or the PC. Language from the
standard states: "when completing the Extreme Temperature Assessment. The benchmark temperature events shall be obtained
from the benchmark library maintained by the ERO or developed by the Planning Coordinators."
2. If an entity runs into the issue of other Planning Coordinators not willing to coordinate, it can reach out to its respective Regional
Entity for assistance. In addition, for compliance purposes, an entity can show that they attempted to coordinate with other
Planning Coordinators within its zone. Essentially, the entity has done all it can and will be able to show that evidence that it
attempted to coordinate and come to consensus.
The implementation plan has standard language and, if entities have issues coordinating with other Planning Coordinators, it can
complete the steps listed above.
The team does not agree with further splitting out zones as multiple iterations have been completed and the focus of FERC Order
896 is coordination between wide areas. The team feels all zones are in a good place for version one of TPL-008.
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Richard Vendetti - NextEra Energy - 5
Answer

No

Document Name
Comment
NextEra does not agree with the modifications to R2. The SAR references the use of either “a projected frequency (e.g., 1-in-50-year
event); or a probability distribution (95th percentile event).” The development of extreme events refers to foot note 9 “Benchmark events
will form the basis for a planner's benchmark planning case— i.e., the base case representing system conditions under the relevant
benchmark event—that will be used to study the potential wide-area impacts of anticipated extreme heat and cold weather events.”
FERC via the SAR requested to develop a base case that is representative of system conditions which could be a 1 in 50 year or a P95
event. Following the proposed language in the standard and the ERO library, the warmest temperature Florida could use for its winter
assessment is 32.3 degrees and the lowest being 24.9F. The concern is that the entire state is at freezing temperatures and will generate
significant winter loads in Florida much larger than the 20% sensitivity we use for winter, thereby generating transmission projects that
will not provide value to our customers. NextEra does not consider this a P95 event, especially if the average 3 rolling day is taking into
consideration (also not requested by the SAR). The coldest temperature experienced in Miami over the last 40 years was during the
winter of 1989, where temperatures were as low as 30 degrees. The lowest 3 day rolling average was 32.6 degrees (12/23-27F, 12/2431F, 12/25-30F and 12/27-38F). The standard as written will force NextEra to plan to a greater than P100 winter loads. This is an unrealistic approach, considering most of Florida’s load is located in Southern Florida south of Lake Okeechobee. NextEra recommends the
language in R2 to state “Represent the 95th percentile extreme conditions for the climate zone based on the 3-day rolling average of
maximum (heat) or minimum (cold) temperature across the zone.”
Likes

0

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Response
Thank you for your comment. The benchmark events are based on 95% of major prior extreme heat and cold weather events over the
past 40 years. If the events provided in the ERO benchmark event library do not work for your zone, you are welcome to work with other
Planning Coordinators within your zone to develop one common extreme heat and one common extreme cold temperature benchmark
event following the expectations laid out in Requirements R2.
Donald Lock - Talen Generation, LLC - 5
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Answer

No

Document Name
Comment
R2.2, "Represent one of the 20 most extreme temperature conditions based on the three-day rolling average of daily maximum (heat) or
daily minimum (cold) temperature across the zone," is far too lax. Selecting the 20th most severe event of the past four decades would
not constitute much of a challenge.
Likes

0

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0

Response
Thank you for your comment. When considering extreme events over a 3-day rolling average over 40-years does not provide a ton of data
to work from. While yes, extreme events have become more common in recent years, it is important for an entity to be able to evaluate
events that happened over 40-years as some of the events may not be extreme compared to other events. It is important to collect 20
extreme events to review and consider which event to study for further studies. This provides enough data for entities to review and
select their worst events for that zone to work from.
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy Houston Electric, LLC (CEHE) believes with the current zone designations, there are some zones where temperature
differences would be significant due to their very large north/south geographical spans. A concern arises whether the chosen extreme
temperature event case is applicable to the overall zone in these cases. It might not be representative of certain parts of the zone.
Transmission Planners should be involved in the selection. CEHE recommends the following revision: Each Planning Coordinator, in
conjunction with its Transmission Planner(s), shall select which extreme heat and extreme cold weather events to develop benchmark
extreme temperature events applicable to their region.
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Dislikes

0

Response
Thank you for your comments. Requirement R1 requires Planning Coordinators and Transmission Planners to identify individual or joint
responsibilities throughout TPL-008-1. It is the teams understanding that Planning Coordinators have the wide area view regarding zones
and the Transmission Planners may not be privy to that specific information, but there is nothing that precludes Transmission Planners
from being involved in conversations for certain parts that are up to Planning Coordinators. The importance of TPL-008-1 and FERC Order
896 is that entities are talking and preparing for extreme temperature events to keep the grid reliable and running so customers maintain
power during these extreme events. FERC Order focus is wide area.
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group
Name SPP RTO
Answer

No

Document Name
Comment
SPP opposes splitting our region into North and South zones. As a contiguously integrated system, our system does not demarcate at
state lines boundaries. We recently completed our 2024 Integrated Transmission Plan that resulted in $7.5B in network upgrades to
further strengthen this integration.
The standard as written could require SPP to select a high and low temperature extreme in both the northern region and southern region,
creating a situation where we are disconnecting the interconnections we built and those planned to in the future. This results in a
needless complication to the existing systems and creates an unnecessary burden that does not improve reliability. As proposed in the
previous version of the document, we request the Planning Coordinator zone be reestablished into a contiguous system for evaluating
these extreme events. The bifurcation is even less appropriate when considering the events proposed in the ERO Enterprise Process for
TPL-008-1 Benchmark Weather Event Development and Maintenance indicate using an event that overlaps both SPP regions from
December 24, 1989. Conversely, the proposed extreme heat case only affected the proposed SPP South Region.
If required to use two zones, we would like to see clarification in the language that indicates regions are allowed to utilize the same
scenario provided it meets the requirements in 2.1 and 2.2.

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Likes

0

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Response
Thank you for your comments. Please see updated language added to Attachment 1. There is nothing that prevents zones from
combining if they find it necessary. Zones identified are the bare minimum and the DT believes are required to meet the wide area needs
of the FERC Order 896. This does not prevent zones from merging.
Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

Yes

Document Name
Comment
We have some comments / observations regarding Req #2 that we would like to share with the SDT:

In Req #2 language, the word ‘select’ has been replaced by ‘identify’. However, we observe that the word ‘select’ is still utilized in
the Measure #2 language, the Req #3 language and in the Technical Rationale document. This inconsistency could cause some confusion
about the actual intent.
For example, the word ‘identify’ might better imply the coordination that is allowed by Req #2.
The Technical Rationale should be updated to highlight and clarify the significance of this wording change.

Req #2 states that the benchmark temperature events shall be obtained from the benchmark library maintained by the ERO or
developed by the Planning Coordinators. Is this implying that some of the benchmark events may not be available on the library after
they are developed by the PCs? If so, is there any expectation (or should there be any) that these benchmark events be somewhat
communicated/shared to other PCs for awareness if they are developed and not on the benchmark library?
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0

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Dislikes

0

Response
Thank you for your comments.
M2. Please see the updated Measure.
TR: R2 language has been updated and the TR does not need to be updated.
R2. All events will be provided by the ERO within the library and all events are posted for entities to prepare for TPL-008-1 first set of five
years required. The flexibility was added to TPL-008-1 to allow entities who wished to develop their own events that opportunity. All
required events will be provided by the ERO in the ERO library by the following the process developed and posted for entities to see. Also,
please see updated TR.
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
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0

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0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
Comment
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December 2, 2024

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FirstEnergy has no concerns with the update to Requirement R2.
Likes

0

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0

Response
Thank you.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Texas RE recommends revising Measure M2 from “…to select one common extreme heat benchmark temperature event” to “to identify
one common extreme heat benchmark temperature event. This makes the language consist with the revision made to Requirement R2.
Likes

0

Dislikes

0

Response
Thank you for your comment. Please see updated measure.
Sharon Darwin - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Southern Company supports EEI’s comments.
Likes

0

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Dislikes

0

Response
Please see the DTs response to EEI.
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

Yes

Document Name
Comment
ITC supports the proposed changes made to Requirement R2.
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
EEI supports the changes made to Requirement R2, which empowers the Planning Coordinator to develop the benchmark temperature
events rather than solely depending on the benchmark temperature events contained in the benchmark library.
Likes

0

Dislikes

0

Response
Thank you for your support.
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Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer

Yes

Document Name
Comment
PNM & TNMP supports EEI’s comments and supports R2.
Likes

0

Dislikes

0

Response
Please see DT’s response to EEI.
Daniel Gacek - Exelon - 1, Group Name Exelon
Answer

Yes

Document Name
Comment
Exelon agrees with the updated proposed TPL-008 Reliability Standard Requirement R2. Additionally, are there any plans to add guidance
regarding “most extreme temperature conditions” in section 2.2? Can a planning coordinator come up with its own criteria/metric
considering that they are likely a broad range of temperatures throughout the weather zone(s) for each temperature events?
Likes

0

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0

Response
Thank you for your comments. The Requirement R2 Part 2.2 is general in which the PCs can discuss within their study zone to determine
what would be appropriate to meet one of the 20 most extreme temperature conditions that are based on the three-day rolling average
of the maximum or minimum temperatures. An example could be the highest three-day rolling average of the maximum temperatures, or

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the lowest three-day rolling average. The PC can document their process based on its documented process criteria for selecting an event
if you do not select an event from the ERO library.
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer

Yes

Document Name
Comment
Ameren agrees with EEI's comments.
Likes

0

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0

Response
Please see the DT’s response to EEI.
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
None.
Likes

0

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0

Response
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer

Yes

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December 2, 2024

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Document Name
Comment
See EEI Comments
Likes

0

Dislikes

0

Response
Please see DT’s response to EEI.
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

Yes

Document Name
Comment
See EEI Comments
Likes

0

Dislikes

0

Response
Please see DT’s response to EEI.
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3,
5, 1, 6; Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

Yes

Document Name
Comment

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Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) on question 1
Likes

0

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0

Response
Please see DT’s response to EEI.
Helen Lainis - Independent Electricity System Operator - 2, Group Name IRC SRC
Answer

Yes

Document Name
Comment
The ISO/RTO Council Standards Review Committee (IRC SRC) generally agrees with the revisions to Requirement R2, and recommends the
following additional revisions to further clarify the Requirement:
Revise the second-to-last sentence at the end of R2 as follows to reference PCs first and the ERO benchmark library second to avoid
a possible inference that the PC is required to develop its own benchmark library:
“The benchmark temperature events shall be developed by the Planning Coordinators or obtained from the benchmark library
maintained by the ERO.”
Revise the last sentence at the end of R2 to read as follows to better reflect the fact that the Planning Coordinator (rather than the
benchmark temperature event) is ultimately the entity making the considerations described in Parts 2.1 and 2.2: “The Planning
Coordinator’s selection of each benchmark temperature event shall:”
Revise Part 2.2 as follows to clarify that the temperature conditions referenced in Part 2.2 are required to fall within the time period
referenced in Part 2.1: “Represent one of the 20 most extreme temperature conditions within the period identified in Part 2.1 based on
the three-day rolling average…”
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Response
Thank you for your comments.
The DT does agree with swapping the order as it does not see a difference. It is clear that you can obtain the info from the ERO library or
develop your own. The TP may consult with the PC on these decisions. This is also laid out in R1 that PCs and TPs will lay out their joint or
individual responsibilities.
Please see updated TPL-008-1 Requirement R2 including PCs.
You cannot complete Part 2.2 without completing 2.1. Your understanding of this is correct and the team does not feel this additional
language is necessary.
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
ERCOT joins the comments submitted by the ISO/RTO Council (IRC) Standards Review Committee (SRC) for this question and adopts them
as its own.
Likes

0

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0

Response
Please see the DT’s response to ISO/RTO
Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer

Yes

Document Name
Comment
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AEPC has signed on to ACES comments. Please review ACES comments.
Likes

0

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0

Response
Please see the DT’s response to ACES.
Chantal Mazza - Chantal Mazza On Behalf of: Junji Yamaguchi, Hydro-Quebec (HQ), 1, 5; Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; Chantal Mazza
Answer

Yes

Document Name
Comment
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0

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0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento
Municipal Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility
District, 3, 6, 4, 1, 5; - Tim Kelley, Group Name SMUD and BANC
Answer

Yes

Document Name
Comment
Likes

0

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Dislikes

0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
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0

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0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

Yes

Document Name
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Comment
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0

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0

Response
Nazra Gladu - Manitoba Hydro - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
Likes

0

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0

Response

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Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Kevin Conway - Western Power Pool - 4
Answer

Yes

Document Name
Comment
Likes

0

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Dislikes

0

Response
Joshua London - Eversource Energy - 1, Group Name Eversource
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
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Comment
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0

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0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response

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Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

Yes

Document Name
Comment
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0

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0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
Likes

0

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Dislikes

0

Response
Greg Sorenson - Greg Sorenson On Behalf of: Tremayne Brown, ReliabilityFirst , 10; - Greg Sorenson
Answer

Yes

Document Name
Comment
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 NPCC RSC
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
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December 2, 2024

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Comment
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0

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0

Response
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric
Company, 3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
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Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer
Document Name
Comment
Abstain
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0

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0

Response

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2. The DT updated Requirement R9 based on comments received. Do you agree? If you do not agree, please provide your
recommendation and, if appropriate, technical or procedural justification.
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group
Name SPP RTO
Answer

No

Document Name
Comment
The current language in R9.4 says revisions to Corrective Action Plans are limited to the subsequent Extreme Temperature Assessments,
yet the underlying system may have change identified through system upgrades. These Corrective Action Plans should be more flexible in
the event a system upgrade is completed or a separate assessment demonstrates the underlying performance issue has been mitigated.
The inclusion of “or other planning assessments” in 9.4 appeared amicable during the drafting team discussion, and we request this be
adopted as proposed in the following revision:
9.4. Be permitted to have revisions to the Corrective Action Plan in subsequent Extreme Temperature Assessments or other planning
assessments, provided that the planned Bulk Electric System shall continue to meet the performance requirements of Table 1.

Likes

0

Dislikes

0

Response
Please see updated Technical Rationale.
Mark Flanary - Midwest Reliability Organization - 10
Answer

No

Document Name
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Comment
MRO is not comfortable with two parts of R9.3, both of which limit significantly the region's ability to meaningfully enforce the
requirement:
1. The terms “regulatory authorities” and “governing bodies” are not specific
2. There are no timing requirements prescribed for the responsible entity concerning when the responsible entity must make its
Corrective Action Plan available to, and solicit feedback from, applicable regulatory authorities or governing bodies responsible for retail
electric service issues.
Likes

0

Dislikes

0

Response
Thank you for your comments. This requirement is addressing the FERC Order 896 directive in P152 that states “we direct NERC to
develop certain processes to facilitate interaction and coordination with applicable regulatory authorities or governing bodies responsible
for retail electric service as appropriate in implementing a corrective action plan.” Lastly, the TPL-008-1 Standard is aligning with what the
FERC Order 896 directs. The DT feels flexibility is an important aspect of the timing requirements. Your Corrective Action Plan should
capture your timing component. In addition, other entities have various processes in place throughout the US and the DT feels it is
important that flexibility be provided for those that have certain processes already in place for soliciting feedback, etc.
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT joins the comments submitted by the IRC SRC for this question and adopts them as its own.
Likes
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0
0

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Response
Please see the DT’s response to IRC SRC.
Helen Lainis - Independent Electricity System Operator - 2, Group Name IRC SRC
Answer

No

Document Name
Comment
The current language in R9.4 says revisions to Corrective Action Plans are limited to subsequent Extreme Temperature Assessments.
However, the underlying system may change between assessments because of system upgrades. These Corrective Action Plans should be
more flexible in the event a system upgrade is completed, or a separate assessment demonstrates the underlying performance issue has
been mitigated. The inclusion of “or other planning assessments” in 9.4 appeared to be acceptable during the drafting team discussion,
and we request this be adopted as proposed in the following revision:
a. 9.4. Be permitted to have revisions to the Corrective Action Plan in subsequent Extreme Temperature Assessments or other planning
assessments, provided that the planned Bulk Electric System shall continue to meet the performance requirements of Table 1.
Likes

0

Dislikes

0

Response
Thank you for your comments. Please see the updated TR.
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
The current draft is not clear what the timeframe is for providing the CAP in R9.1. In addition, there is no timeframe when to notify the
applicable regulatory authorities or governing bodies in R9.2. CEHE strongly disagrees with the following statement in R9.3: “Make its
Corrective Action Plan available to, and solicit feedback from, applicable regulatory authorities or governing bodies responsible for retail
Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

39

electric service issues.” CEHE recommends that “applicable regulatory authorities or governing bodies” be defined. CEHE also
recommends that TPs should be providing CAP information only to their PC.
Likes

0

Dislikes

0

Response
Thank you for your comments. Please see the updated TR.
This requirement is addressing the FERC Order 896 directive in P152 that states “we direct NERC to develop certain processes to facilitate
interaction and coordination with applicable regulatory authorities or governing bodies responsible for retail electric service as
appropriate in implementing a corrective action plan.” Lastly, the TPL-008-1 Standard is aligning with what the FERC Order 896 directs.
The DT feels flexibility is an important aspect of the timing requirements. Your Corrective Action Plan should capture your timing
component. In addition, other entities have various processes in place throughout the US and the DT feels it is important that flexibility be
provided for those that have certain processes already in place for soliciting feedback, etc.
Richard Vendetti - NextEra Energy - 5
Answer

No

Document Name
Comment
NextEra does not agree with the language of R9.3 regarding the solicitation of feedback, as this is in line and satisfied through R11 of the
standard.
Likes

0

Dislikes

0

Response
Thank you for your comment. R9 and R11 require different objectives.

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

40

R9 addresses FERC Order 896 by requiring feedback from regulatory authorities and governing bodies. This requirement is addressing the
FERC Order 896 directive in P152 that states “we direct NERC to develop certain processes to facilitate interaction and coordination with
applicable regulatory authorities or governing bodies responsible for retail electric service as appropriate in implementing a corrective
action plan.”
R11 is providing your information to RCs.
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer

No

Document Name
Comment
During the recent revisions, a proposal was made with support to clarify 9.4 that revisions to a Corrective Action Plan should be allowed if
other planning assessments resolve the concern. As such this should be captured in requirement 9.4 such as the following:
9.4. Be permitted to have revisions to the Corrective Action Plan in subsequent Extreme Temperature Assessments or other planning
assessments, provided that the planned Bulk Electric System shall continue to meet the performance requirements of Table 1.
Likes

1

Dislikes

Scott Brame, N/A, Brame Scott
0

Response
Thank you for your comment. Please see the updated TR.
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
•
•

The purpose and required response actions related to the sharing of CAPs and solicitation of feedback is not clear.
Documentation of alternatives is an additional administrative burden and provides little benefit to reliability. It is also unclear if
there is some type of expectation these alternatives are reviewed or potentially challenged as invalid.

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

41

•
•

•

The role of the TO and/or GO in implementing or otherwise responding to CAPs that may require additions or modifications to
their systems/facilities is not captured in these requirements.
There appears to be a significant amount of outside review required but no clear actions the responsible entity is required to take,
particularly if there is a dispute. What is the purpose of the review and the expected response? This potentially produces an
undue burden on the PC/TP and adds subjectivity in requiring a review with no documented guidelines for conducting the review.
GTC recommends the restructuring of requirement 9 such that documentation of alternatives along with the sharing and soliciting
feedback back is only necessary when utilizing Non-Consequential Load Loss as an interim solution.

Likes

0

Dislikes

0

Response
Thank you for your comments.
FERC Order No. 896 directs NERC “to develop certain processes to facilitate interaction and coordination with applicable regulatory
authorities or governing bodies responsible for retail electric service as appropriate in implementing a corrective action plan” (¶152). In
the event that Non-Consequential Load Loss is included in the Corrective Action Plan for a P1 Contingency, the responsible entity shall
document alternative(s) considered, make the Corrective Action Plan available to, and solicit feedback from, applicable regulatory
authorities or governing bodies responsible for retail electric service issues. So long as an entity makes its Corrective Action Plan available
to, and solicit feedback from, applicable regulatory authorities or governing bodies responsible for retail electric service issues, and
determines that it needs to move forward with its CAP, you have successfully completed what is required of R9 Part 9.3.
The charge of the SAR does not incorporate TOs and GOs. This is a planning standard.
Based on review of the FERC Order, CAPs are for all types stated in TPL-008-1. TPL-008-1 is assisting in ensuring entities are prepared for
extreme temperature events and know how to keep the grid reliable and the power on. Please read FERC Order 896. It states in P 153.
“We adopt our rationale set forth in the NOPR and conclude that the directive to require the development of corrective action plans is
needed for Reliable Operation of the Bulk-Power System. Under the currently effective Reliability Standard TPL-001-5.1, planning
coordinators and transmission planners are required to evaluate possible actions to reduce the likelihood or mitigate the consequences of
extreme weather events, but are not obligated to develop corrective action plans, even if such events are found to cause cascading
outages. Experience over the past decade has demonstrated that the potential severity of extreme heat and cold weather events
exacerbates the likelihood to cause system instability, uncontrolled separation, or cascading failures as a result of a sudden disturbance or
unanticipated failure of system elements. Thus, we conclude that entities should proactively address known system vulnerabilities by
Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

42

developing corrective action plans that include mitigation for specified instances where performance requirements for extreme heat and
cold events are not met”.
Joshua London - Eversource Energy - 1, Group Name Eversource
Answer

No

Document Name
Comment
Eversource has concerns regarding compliance with Requirement R9.3. Because this standard is focused on “Extreme Temperature
Events”, the company can foresee issues with regulatory agencies not wanting the company to invest significant funds into these issues.
What would occur if Eversource supplied a CAP to the appropriate governing body and they state they do not agree the work is
necessary? Would creating the CAP still meet the intent of the requirement although it may not be allowed to be implemented?
Eversource recommends the DT consider adding language in case such a scenario arises.
Likes

0

Dislikes

0

Response
Thank you for your comments.
FERC Order No. 896 directs NERC “to develop certain processes to facilitate interaction and coordination with applicable regulatory
authorities or governing bodies responsible for retail electric service as appropriate in implementing a corrective action plan” (¶152). In
the event that Non-Consequential Load Loss is included in the Corrective Action Plan for a P1 Contingency, the responsible entity shall
document alternative(s) considered, make the Corrective Action Plan available to, and solicit feedback from, applicable regulatory
authorities or governing bodies responsible for retail electric service issues. So long an entity makes its Corrective Action Plan available to,
and solicit feedback from, applicable regulatory authorities or governing bodies responsible for retail electric service issues, and
determines that it needs to move forward with its CAP, you have successfully completed what is required of R9 Part 9.3. Lastly, if you
solicit the feedback and make aware options, such as, load shed opportunities, etc. You are not required to get regulatory approval nor
can you force the regulatory authority to respond. You have done what is required of the requirement. In the end permits could be
achieved, etc. consistent with requirement.
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

43

Answer

No

Document Name
Comment
We recommend that further clarification be given to how “applicable” regulatory authorities or governing bodies are determined.
Likes

0

Dislikes

0

Response
Thank you for your comment. This would be the regulatory authorities or governing bodies that may have authority on rate making or
permitting transmission upgrade authorities, etc. (state public utility commission. local municipal utilities, etc.)
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer

No

Document Name
Comment
Oncor strongly disagrees with the following statement in R9.3: “Make its Corrective Action Plan available to, and solicit feedback from,
applicable regulatory authorities or governing bodies responsible for retail electric service issues.” We propose that “applicable regulatory
authorities or governing bodies” be defined and limited. For example, a TP should only need to provide their PC with CAP information.
Likes

0

Dislikes

0

Response
Thank you for your comments. This requirement is addressing the FERC Order 896 directive in P152 that states “we direct NERC to
develop certain processes to facilitate interaction and coordination with applicable regulatory authorities or governing bodies responsible
for retail electric service as appropriate in implementing a corrective action plan.” Lastly, the TPL-008-1 Standard is aligning with what the
FERC Order 896 directs. The DT did its best to align with TPL-001 while meeting the FERC Order 896 directives.
Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
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44

In addition, the individual or joint responsibilities are determined in R1 by the TP and PC.
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
1) Based on other projects that include developing and implementing CAPs, USV does not agree with the proposed modifications and
would feel more confident if there were guidelines and more structured timelines set for the CAPs. Perhaps not in the standard itself, but
guidance on timelines could be explained in the technical rationale and include timelines for implementing CAPs and when entities can
utilize backup action plans such as Non-Consequential Load Loss.

2) The newly proposed modifications to R9 compared to the proposed modifications from the previous draft do not change the
obligations for responsible entities. The new requirement 9.3 is administrative in nature and does not appear to provide any increase in
reliability, if anything it would delay the implementation of the CAP. USV understands the directives in FERC order 896 and the need for
R9. However, we disagree that any significant improvements have been made to previously proposed R9 modifications.
Likes

0

Dislikes

0

Response
Thank you for your comments.
The DT feels flexibility is an important aspect of the timing requirements. Your Corrective Action Plan should capture your timing
component. In addition, other entities have various processes in place throughout the US and the DT feels it is important that flexibility be
provided for those that have certain processes already in place for soliciting feedback, etc.
Requirement R9 Part 9.3 is addressing the FERC Order 896 directive in P152 that states “we direct NERC to develop certain processes to
facilitate interaction and coordination with applicable regulatory authorities or governing bodies responsible for retail electric service as
Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

45

appropriate in implementing a corrective action plan.” Lastly, the TPL-008-1 Standard is aligning with what the FERC Order 896 directs.
The DT did its best to align with TPL-001 while meeting the FERC Order 896 directives.
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3,
5, 1, 6; Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

Yes

Document Name
Comment
Evergy supports and incorporates by reference the comments of the Midwest Reliability Organization's NERC Standards Review Forum
(MRO NSRF) on question 2
Likes

0

Dislikes

0

Response
Please see the DT’s response to MRO NSRF.
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

Yes

Document Name
Comment
See EEI Comments
Likes

0

Dislikes

0

Response
Please see the DT’s response to EEI.
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December 2, 2024

46

Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
None.
Likes

0

Dislikes

0

Response
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer

Yes

Document Name
Comment
Ameren agrees with EEI's comments.
Likes

0

Dislikes

0

Response
Please see the DT’s response to EEI.
Daniel Gacek - Exelon - 1, Group Name Exelon
Answer

Yes

Document Name
Comment
Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

47

Exelon agrees with the updated proposed TPL-008 Reliability Standard Requirements R9.
Likes

0

Dislikes

0

Response
Thank you for your support.
Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer

Yes

Document Name
Comment
PNM & TNMP agrees with R9.
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
EEI supports the changes made to Requirement R9 and offers no additional changes.
Likes
Dislikes

0
0

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48

Response
Thank you for your support.
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

Yes

Document Name
Comment
ITC supports the proposed changes made to Requirement R9.
Likes

0

Dislikes

0

Response
Thank you for your support.
Sharon Darwin - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Southern Company supports EEI’s comments.
Likes

0

Dislikes

0

Response
Please see the DT’s response to EEI.
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

49

Document Name
Comment
FirstEnergy has no concerns with the update to Requirement R9.
Likes

0

Dislikes

0

Response
Thank you.
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
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50

Dislikes

0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric
Company, 3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

Yes

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December 2, 2024

51

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 NPCC RSC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Greg Sorenson - Greg Sorenson On Behalf of: Tremayne Brown, ReliabilityFirst , 10; - Greg Sorenson
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

52

Donald Lock - Talen Generation, LLC - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

53

Likes

0

Dislikes

0

Response
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

Yes

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

54

Document Name
Comment
Likes

0

Dislikes

0

Response
Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Kevin Conway - Western Power Pool - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
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December 2, 2024

55

Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Nazra Gladu - Manitoba Hydro - 1
Answer

Yes

Document Name
Comment

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

56

Likes

0

Dislikes

0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

Yes

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December 2, 2024

57

Document Name
Comment
Likes

0

Dislikes

0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento
Municipal Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility
District, 3, 6, 4, 1, 5; - Tim Kelley, Group Name SMUD and BANC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Junji Yamaguchi, Hydro-Quebec (HQ), 1, 5; Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; Chantal Mazza
Answer

Yes

Document Name
Comment

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58

Likes

0

Dislikes

0

Response
Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer
Document Name
Comment
See EEI Comments
Likes

0

Dislikes

0

Response
Please see the DT’s response to EEI.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE continues to recommend including a timeframe for which the CAPs need to be developed and implemented once the
benchmark planning case study results indicate the System is unable to meet performance requirements. Requirement R2 states: “Be
permitted to utilize Non-Consequential Load Loss as an interim solution, which normally is not permitted for category P0 in Table 1, in for
situations that are beyond the control of the Planning Coordinator or Transmission Planner that prevent the implementation of a
Corrective Action Plan in the required timeframe…” Texas RE reads the proposed standard language as allowing the entity to determine
the “required timeframe.” While the revised language provides for a coordination process with regulatory authorities, it does not appear
these entities could reject a Corrective Action Plan if the required timeframe was unduly extended. Texas RE therefore continues to
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59

recommend placing more explicit requirements around CAP development and implementation to prevent unilaterally lengthy CAPs and
ensure their timely and effective implementation.
Likes

0

Dislikes

0

Response
Thank you for your comment. The DT feels flexibility is an important aspect of the timing requirements. Your Corrective Action Plan
should capture your timing component. In addition, other entities have various processes in place throughout the US and the DT feels it is
important that flexibility be provided for those that have certain processes already in place for soliciting feedback, etc.

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60

3. The DT updated Attachment 1 based on comments received. Do you agree? If you do not agree, please provide your
recommendation and, if appropriate, technical or procedural justification.
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

Document Name
Comment
The SDT made vast improvements to Attachment 1 by splitting MISO and SPP zones into MISO North, MISO South, SPP North, and SPP
South. The SDT attempted to move the disjointed sections of SERC Central to the appropriate MISO or SPP zones. However, the SDT
needs to include geographical boundaries to clarify which SERC Central PCs should belong to MISO North, MISO South, SPP North, and
SPP South. For example:
•
•

Zone - “MISO South”
Planning Coordinator(s) – “Planning Coordinator(s) in MISO and SERC that serve portions of Montana, North Dakota, South
Dakota, Minnesota, Iowa, Wisconsin, Michigan, Indiana, Illinois, Missouri, or Kentucky”

Likes

0

Dislikes

0

Response
Thank you for your comment. The DT does not agree that boundaries would be beneficial. Keeping that map as a noncompliance visual
aid allows entities to see an approximation and this also assists in the future changes to boundaries. However, the attachment 1 table
provides the details needed when determining Planning Coordinator locations within the zones.
Adrian Andreoiu - BC Hydro and Power Authority - 1, Group Name BC Hydro
Answer

No

Document Name
Comment
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61

B.C. has a wide geographic area, applying one common extreme temperature is not ideal. The Canada West cold benchmark event
temperatures are closer to our BC Hydro south region coldest days temperature. However, as winter peaking utilities, most of BC Hydro’s
temperature sensitive load (mostly distribution load) are located in the Lower Mainland and Vancouver Island.
BC Hydro recommends that the Canada West zone be split into BC and Alberta based on weather and geographical differences that are
more conducive to a robust ETA.

Likes

0

Dislikes

0

Response
Thank you for your comment. The team does not agree with further splitting out zones.
FERC Order 896 explains the importance of coordination among entities, which has been reflected in the TPL-008-1 standard. It is time for
Planning Coordinators to discuss and plan for future events to promote reliability on the grid and prevent black outs due to extreme
temperature events. As stated before, if entities within a zone have trouble determining common events to work from, additional
meetings need to be scheduled among one another to coordinate and talk through the best event to work from or reach out to the
respective Regional Entity for assistance. Pull wide area comment from FERC Order.
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
Please view response to Question 1.
Likes

0

Dislikes

0

Response
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62

Please see the DT’s response to Q1.
Helen Lainis - Independent Electricity System Operator - 2, Group Name IRC SRC
Answer

No

Document Name
Comment
It is not clear to the IRC SRC whether the current draft addresses temperature variances from east to west of the current zones, not just
north to south. For example, entities with a wide east to west territory may have vastly different climates that may need to be split into
additional zones.
During the last comment review, the drafting team discussion indicated that a Planning Coordinator with more than one zone may utilize
the same weather event. Ideally the drafting team would revert to the contiguous planning coordinator zones. Either way, this
understanding, that two zones within a single PC may use the same event, should be documented within the standard to ensure there is
no ambiguity should an entity carry out such approach. The IRC SRC would like to see clarification in the language that indicates regions
are allowed to utilize the same scenario provided it meets the requirements in 2.1 and 2.2.
ERCOT, IESO, and PJM abstain from IRC SRC response and comments to Q3.
Likes

0

Dislikes

0

Response
Thank you for your comment. Please see updated language added to Attachment 1 in TPL-008-1.
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group
Name SPP RTO
Answer

No

Document Name
Comment

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63

SPP’s PC footprint should not be split into northern and southern zones (see question #1).
Likes

0

Dislikes

0

Response
Please see DT’s response to Q1.
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
Comment
FirstEnergy has no concerns with the update to Attachment 1.
Likes
Dislikes

0
0

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64

Response
Thank you.
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
In the attachment 1, remove “WECC” from “WECC Southwest” to match up with the Zones Map.
Likes

0

Dislikes

0

Response
Thank you for your comment. The DT does not agree that boundaries would be beneficial. Keeping that map as a noncompliance visual
aid allows entities to see an approximation and this also assists in the future changes to boundaries. However, the attachment 1 table
provides the details needed when determining Planning Coordinator locations within the zones.
Sharon Darwin - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Southern Company supports EEI’s comments.
Likes

0

Dislikes

0

Response
Please see the DT’s response to EEI.
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Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

Yes

Document Name
Comment
ITC supports the proposed changes made to Attachment 1 zones.
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
EEI supports the changes made to Attachment 1.
Likes

0

Dislikes

0

Response
Please see the DT’s response to EEI.
Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer

Yes

Document Name
Comment
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PNM & TNMP agrees with the changes to Attachment 1.
Likes

0

Dislikes

0

Response
Thank you for your support.
Daniel Gacek - Exelon - 1, Group Name Exelon
Answer

Yes

Document Name
Comment
Exelon agrees with the updates made to the table and map in Attachment 1.
Likes

0

Dislikes

0

Response
Thank you for your support.
Greg Sorenson - Greg Sorenson On Behalf of: Tremayne Brown, ReliabilityFirst , 10; - Greg Sorenson
Answer

Yes

Document Name
Comment
There may be only limited value in running dynamic analysis on a Long-Term planning case (i.e. 10 yr out case). And these cases are
difficult to build and are often not N-1 secure (meaning not all single contingencies will result in a valid load flow solution). Given this,
and the multiple future assumptions, the dynamic portion of the studies may not provide tangible value.”

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Likes

0

Dislikes

0

Response
Thank you for your comment. FERC directive to look at both flows and stability analysis. This is a long term focus too and is no different
than transient stability of TPL-001 long term assessment.
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer

Yes

Document Name
Comment
Ameren agrees with EEI's comments.
Likes

0

Dislikes

0

Response
Please see the DT’s response to EEI.
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer

Yes

Document Name
Comment
None.
Likes

0

Dislikes

0

Response
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December 2, 2024

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Stephanie Kenny - Edison International - Southern California Edison Company - 6
Answer

Yes

Document Name
Comment
See EEI Comments
Likes

0

Dislikes

0

Response
Please see the DT’s response to EEI.
Selene Willis - Edison International - Southern California Edison Company - 5
Answer

Yes

Document Name
Comment
See EEI Comments
Likes

0

Dislikes

0

Response
Please see the DT’s response to EEI.
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

Yes

Document Name

Draft 4 Attachment 1 Example.pdf

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December 2, 2024

69

Comment
The Attachment 1 graphic would greatly benefit from including state boundaries. Please see attached example.
Draft 4 Attachment 1 Example.pdf
Likes

0

Dislikes

0

Response
Thank you for your comment. The DT does not agree that boundaries would be beneficial. Keeping that map as a noncompliance visual
aid allows entities to see an approximation and this also assists in the future changes to boundaries. However, the attachment 1 table
provides the details needed when determining Planning Coordinator locations within the zones.
Chantal Mazza - Chantal Mazza On Behalf of: Junji Yamaguchi, Hydro-Quebec (HQ), 1, 5; Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; Chantal Mazza
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento
Municipal Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility
District, 3, 6, 4, 1, 5; - Tim Kelley, Group Name SMUD and BANC
Answer

Yes

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Document Name
Comment
Likes

0

Dislikes

0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 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
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December 2, 2024

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Nazra Gladu - Manitoba Hydro - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

72

Likes

0

Dislikes

0

Response
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Kevin Conway - Western Power Pool - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Joshua London - Eversource Energy - 1, Group Name Eversource
Answer

Yes

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

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Document Name
Comment
Likes

0

Dislikes

0

Response
Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

74

Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Richard Vendetti - NextEra Energy - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

75

Likes

0

Dislikes

0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Donald Lock - Talen Generation, LLC - 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 NPCC RSC
Answer

Yes

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December 2, 2024

76

Document Name
Comment
Likes

0

Dislikes

0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3,
5, 1, 6; Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

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December 2, 2024

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Response
Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer

Yes

Document Name
Comment
Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
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Likes

0

Dislikes

0

Response
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric
Company, 3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
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

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Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer
Document Name
Comment
Abstain
Likes

0

Dislikes

0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE continues to be concerned that multiple contingencies may not be used to assess the system in extreme temperature events. In
Requirement R7, Table 1 only shows single contingencies and double circuit contingencies for assessing steady state and stability
performances. Based on the contingencies listed in Table 1, the reasoning for R7 is not clear. Are the responsible entities expected to
select single contingencies and double circuit contingencies and use those contingencies to assess the system? During extreme
temperature events, multiple overlapping contingencies are expected and frequently occur. Given this fact, the proposed standard
should correspondingly require Registered entities to study overlapping contingencies to identify system deficiencies and prepare the
mitigation plans.
Likes

0

Dislikes

0

Response
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December 2, 2024

80

Thank you for your comment. Please see the technical rationale document. This is a minimum requirement. Any responsible entity that
feels they want to go beyond what is required, is welcome to do so.
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Document Name
Comment
During the last comment review, the drafting team discussion indicated that a Planning Coordinator with more than one zone may utilize
the same weather event. This understanding should be documented within the standard to ensure there is no ambiguity should an entity
conduct such an approach. The MRO-NSRF would like to see clarification in the language that indicates regions are allowed to utilize the
same scenario provided it meets the requirements in 2.1 and 2.2.
Likes

1

Dislikes

Scott Brame, N/A, Brame Scott
0

Response
Thank you for your comment. Please see the updated language added to attachment 1 in TPL-008-1.

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4. The DT believes proposed modifications in TPL-008-1 provide entities with flexibility to meet the reliability objectives in a costeffective manner. Do you agree? If you do not agree, or if you agree but have suggestions for improvement to enable more costeffective approaches, please provide your recommendation and, if appropriate, technical or procedural justification.
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric
Company, 3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer

No

Document Name
Comment
Sensitivity to generation, load and transfers are already studied as part of TPL-001-5.1 yearly for near and long-term scenarios (year
10/year 12). The sensitivity additional studies proposed for R8.2 are unlikely to yield any new information and will be duplicative work for
Transmission Planners.
The Extreme Temperature Assessment is already a very extreme sensitivity study itself that should already capture modified load,
generation, transmission, and transfers befitting this analysis per R3, so it is not needed nor appropriate to study sensitivities for
sensitivity cases. Further sensitivity cases to adjust such power flow variables would be a nice idea, but it does not appear cost effective
to mandate developing and evaluating “sensitivity” cases in addition to the already sensitive nature if the extreme weather assessment.
If sensitivity cases are deemed necessary, it would be more cost-effective to waive the obligation to study and analyze stability for those
sensitivities.
Likes

0

Dislikes

0

Response
Thank you for your comment. FERC Order 896 P 2. States: “We take this action to address challenges associated with planning for
extreme heat and cold weather events, particularly those that occur during periods when the Bulk-Power System must meet
unexpectedly high demand. Extreme heat and cold weather events have occurred with greater frequency in recent years, and are
projected to occur with even greater frequency in the future. These events have shown that load shed during extreme temperature
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result in unacceptable risk to life and have extreme economic impact. As such, the impact of concurrent failures of Bulk-Power System
generation and transmission equipment and the potential for cascading outages that may be caused by extreme heat and cold weather
events should be studied and corrective actions should be identified and implemented." Therefore, additional preparation and planning
are needed.” The DT did its best to draft TPL-008-1 in a cost-effective manner; however, some costs will be required based on the
importance of the reliability of the grid.
Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group
Name SPP RTO
Answer

No

Document Name
Comment
The changes to the zoning and mapping create an administrative burden with little benefit to the reliability based upon the current
language. This requires coordination with ourselves and the proposed event library recommends the same across our entire
footprint. This would not be cost effective to create multiple models and sensitivities which would not leverage the transmission system
built to support reliability.
Likes

0

Dislikes

0

Response
Thank you for your comment. FERC Order 896 P 2. States: “We take this action to address challenges associated with planning for
extreme heat and cold weather events, particularly those that occur during periods when the Bulk-Power System must meet
unexpectedly high demand. Extreme heat and cold weather events have occurred with greater frequency in recent years, and are
projected to occur with even greater frequency in the future. These events have shown that load shed during extreme temperature
result in unacceptable risk to life and have extreme economic impact. As such, the impact of concurrent failures of Bulk-Power System
generation and transmission equipment and the potential for cascading outages that may be caused by extreme heat and cold weather
events should be studied and corrective actions should be identified and implemented." Therefore, additional preparation and planning
are needed.” The DT did its best to draft TPL-008-1 in a cost-effective manner; however, some costs will be required based on the
importance of the reliability of the grid.
Diana Aguas - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
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December 2, 2024

83

Answer

No

Document Name
Comment
CEHE believes the new draft TPL-008-1 still imposes a cost and time burden to PCs/TPs without substantial benefits to reliability of BPS.
To support this standard CEHE would like to learn more information on any economic analysis that was performed.
Likes

0

Dislikes

0

Response
Thank you for your comment. FERC Order 896 P 2. States: “We take this action to address challenges associated with planning for
extreme heat and cold weather events, particularly those that occur during periods when the Bulk-Power System must meet
unexpectedly high demand. Extreme heat and cold weather events have occurred with greater frequency in recent years, and are
projected to occur with even greater frequency in the future. These events have shown that load shed during extreme temperature
result in unacceptable risk to life and have extreme economic impact. As such, the impact of concurrent failures of Bulk-Power System
generation and transmission equipment and the potential for cascading outages that may be caused by extreme heat and cold weather
events should be studied and corrective actions should be identified and implemented." Therefore, additional preparation and planning
are needed.” The DT did its best to draft TPL-008-1 in a cost-effective manner; however, some costs will be required based on the
importance of the reliability of the grid.
Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
See our comments for Question 1.
Likes
Dislikes

0
0

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84

Response
Please see DT’s response to Q1.
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer

No

Document Name
Comment
•

•

ITC believes it is not cost effective to build sensitivity models and analyze the required events yet not require any Corrective
Action Plans. If these cases have value and justification to be created and analyzed, then the problems generated within them are
also justified to need mitigation to assure reliability.
Corrective Action plans utilizing only Non Consequential Load Loss do not provide value regarding reliability objectives. Reliability
should aim to maintain service to serve firm load and for single contingencies when it may be critical to end users/load under
extreme temperature conditions. Entities would need to proactively start shedding load for changes in generation, real and
reactive forecasted Load, or transfers; load shed is not a solution to the problems identified on how to deliver reliable service to
load.

Likes

0

Dislikes

0

Response
Thank you for your comment. FERC Order 896 P 2. States: “We take this action to address challenges associated with planning for
extreme heat and cold weather events, particularly those that occur during periods when the Bulk-Power System must meet
unexpectedly high demand. Extreme heat and cold weather events have occurred with greater frequency in recent years, and are
projected to occur with even greater frequency in the future. These events have shown that load shed during extreme temperature
result in unacceptable risk to life and have extreme economic impact. As such, the impact of concurrent failures of Bulk-Power System
generation and transmission equipment and the potential for cascading outages that may be caused by extreme heat and cold weather
events should be studied and corrective actions should be identified and implemented." Therefore, additional preparation and planning
are needed.” The DT did its best to draft TPL-008-1 in a cost-effective manner; however, some costs will be required based on the
importance of the reliability of the grid.
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer

No

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85

Document Name
Comment
The attempt for flexibility is appreciated but this standard still falls short of something that is clear and allows the PC/TP to appropriately
plan to meet reliability goals during extreme temperature events. The inclusion of outside entity reviews of CAPs offers the reviewer
flexibility as there are no bounds provided to them. The PC/TP, however, is potentially impacted by subjective reviews that have no
framework with which the PC/TP can effectively respond.
Likes

0

Dislikes

0

Response
Thank you for your comment. FERC Order 896 P 2. States: “We take this action to address challenges associated with planning for
extreme heat and cold weather events, particularly those that occur during periods when the Bulk-Power System must meet
unexpectedly high demand. Extreme heat and cold weather events have occurred with greater frequency in recent years, and are
projected to occur with even greater frequency in the future. These events have shown that load shed during extreme temperature
result in unacceptable risk to life and have extreme economic impact. As such, the impact of concurrent failures of Bulk-Power System
generation and transmission equipment and the potential for cascading outages that may be caused by extreme heat and cold weather
events should be studied and corrective actions should be identified and implemented." Therefore, additional preparation and planning
are needed.” The DT did its best to draft TPL-008-1 in a cost-effective manner; however, some costs will be required based on the
importance of the reliability of the grid.
Jessica Cordero - Unisource - Tucson Electric Power Co. - 1
Answer

No

Document Name
Comment
New Standard requiring extensive coordination with adjacent PCs/TPs within the defined “zones”. New Standards impose a cost and time
burden to PCs/TPs without necessarily providing substantial benefits to the reliability of the BPS.
Likes

0

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December 2, 2024

86

Dislikes

0

Response
Thank you for your comment. FERC Order 896 P 2. States: “We take this action to address challenges associated with planning for
extreme heat and cold weather events, particularly those that occur during periods when the Bulk-Power System must meet
unexpectedly high demand. Extreme heat and cold weather events have occurred with greater frequency in recent years, and are
projected to occur with even greater frequency in the future. These events have shown that load shed during extreme temperature
result in unacceptable risk to life and have extreme economic impact. As such, the impact of concurrent failures of Bulk-Power System
generation and transmission equipment and the potential for cascading outages that may be caused by extreme heat and cold weather
events should be studied and corrective actions should be identified and implemented." Therefore, additional preparation and planning
are needed.” The DT did its best to draft TPL-008-1 in a cost-effective manner; however, some costs will be required based on the
importance of the reliability of the grid.
Steven Taddeucci - NiSource - Northern Indiana Public Service Co. - 3
Answer

No

Document Name
Comment
This should be part of TPL-001 and not a separate TPL Standard.
Likes

0

Dislikes

0

Response
Thank you for your comment. FERC Order 896 P 2. States: “We take this action to address challenges associated with planning for
extreme heat and cold weather events, particularly those that occur during periods when the Bulk-Power System must meet
unexpectedly high demand. Extreme heat and cold weather events have occurred with greater frequency in recent years, and are
projected to occur with even greater frequency in the future. These events have shown that load shed during extreme temperature
result in unacceptable risk to life and have extreme economic impact. As such, the impact of concurrent failures of Bulk-Power System
generation and transmission equipment and the potential for cascading outages that may be caused by extreme heat and cold weather
events should be studied and corrective actions should be identified and implemented." Therefore, additional preparation and planning
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87

are needed.” The DT did its best to draft TPL-008-1 in a cost-effective manner; however, some costs will be required based on the
importance of the reliability of the grid.
The DT felt draft a new standard made the best sense to address the 25+ FERC directives from FERC Order 896 instead of trying to add all
that is required to the current TPL-001.
Jennifer Weber - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
At this time, we are unable to fully agree that this standard provides the necessary flexibility to meet the reliability objectives in a costeffective manner. We would be interested in more information on any economic analysis that was performed.
Likes

0

Dislikes

0

Response
Thank you for your comment. FERC Order 896 P 2. States: “We take this action to address challenges associated with planning for
extreme heat and cold weather events, particularly those that occur during periods when the Bulk-Power System must meet
unexpectedly high demand. Extreme heat and cold weather events have occurred with greater frequency in recent years, and are
projected to occur with even greater frequency in the future. These events have shown that load shed during extreme temperature
result in unacceptable risk to life and have extreme economic impact. As such, the impact of concurrent failures of Bulk-Power System
generation and transmission equipment and the potential for cascading outages that may be caused by extreme heat and cold weather
events should be studied and corrective actions should be identified and implemented." Therefore, additional preparation and planning
are needed.” The DT did its best to draft TPL-008-1 in a cost-effective manner; however, some costs will be required based on the
importance of the reliability of the grid.
Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer

Yes

Document Name
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December 2, 2024

88

Comment
FirstEnergy has no concerns with the cost-effectiveness of this draft.
Likes

0

Dislikes

0

Response
Thank you.
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

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December 2, 2024

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Response
Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Carver Powers - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3,
5, 1, 6; Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer

Yes

Document Name
Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

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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 NPCC RSC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Daniel Gacek - Exelon - 1, Group Name Exelon
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response

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Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Mike Magruder - Avista - Avista Corporation - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Hillary Creurer - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

92

Dislikes

0

Response
Sharon Darwin - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Donna Wood - Tri-State G and T Association, Inc. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Gary Trezza - Long Island Power Authority - 1 - NPCC
Answer

Yes

Document Name
Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

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Comment
Likes

0

Dislikes

0

Response
Kevin Conway - Western Power Pool - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response

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December 2, 2024

94

Nazra Gladu - Manitoba Hydro - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer

Yes

Document Name
Comment
Likes

0

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December 2, 2024

95

Dislikes

0

Response
Tim Kelley - Tim Kelley On Behalf of: Charles Norton, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Foung Mua, Sacramento
Municipal Utility District, 3, 6, 4, 1, 5; Kevin Smith, Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal
Utility District, 3, 6, 4, 1, 5; Ryder Couch, Sacramento Municipal Utility District, 3, 6, 4, 1, 5; Wei Shao, Sacramento Municipal Utility
District, 3, 6, 4, 1, 5; - Tim Kelley, Group Name SMUD and BANC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Chantal Mazza - Chantal Mazza On Behalf of: Junji Yamaguchi, Hydro-Quebec (HQ), 1, 5; Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; Chantal Mazza
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response

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96

Dwanique Spiller - Berkshire Hathaway - NV Energy - 5
Answer
Document Name
Comment
NV Energy does not have a comment regarding the cost-effectiveness.
Likes

0

Dislikes

0

Response
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
Duke Energy’s focus is on system reliability and will not respond to the cost effectiveness question.
Likes

0

Dislikes

0

Response
Thank you.
Danielle Moskop - Danielle Moskop On Behalf of: David Jendras Sr, Ameren - Ameren Services, 3, 6, 1; - Danielle Moskop
Answer
Document Name
Comment
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Ameren prefers not to comment on the cost effectiveness of the project.
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Thank you.
Rachel Schuldt - Black Hills Corporation - 6, Group Name Black Hills Corporation - All Segments
Answer
Document Name
Comment
Black Hills Corporation will not comment on cost effectiveness.
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Thank you.
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer
Document Name
Comment
Abstain
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Response

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5. Provide any additional comments for the drafting team to consider, including the provided technical rationale document, if desired.
Chantal Mazza - Chantal Mazza On Behalf of: Junji Yamaguchi, Hydro-Quebec (HQ), 1, 5; Nicolas Turcotte, Hydro-Quebec (HQ), 1, 5; Chantal Mazza
Answer
Document Name
Comment
HQ supports these revisions.
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Thank you for your support.
Alyssia Rhoads - Public Utility District No. 1 of Snohomish County - 1
Answer
Document Name
Comment
Requirement R10 should explicitly clarify that a Corrective Action Plan is not required for P7 Contingencies, as stated in the previous draft
2, Table 2.1, page 11.
R6 VRF is 'High', but it should be set as ‘Medium’ to match TPL-008 R5.
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Thank you for your comment.
R10. The DT finds R10 to be clear as a Corrective Action Plan is not stated anywhere in R10. This is a possible action that is required.
VRF: The DT determined that based on the planning for events such as instability, uncontrolled separation, or Cascading events would
consist of a high VRF and therefore, kept the VRF as high. This is consistent with the definition of a high VRF in the justification document
provided on the NERC website.
Thomas Foltz - AEP - 5
Answer
Document Name
Comment
AEP offers the following additional comments regarding potential overlapping or duplicative obligations.
R3 and R4 appear duplicative in that they both involve the formation of study cases. R3 states “Implement a process for developing
benchmark planning cases” while R4 states “Use the coordination process… to develop the following… planning benchmark cases.” R1’s
“shall complete its responsibilities such that the … assessment is completed…” appears duplicative with R8’s “shall complete steady-state
and stability analysis… ”. AEP recommends removing the last sentence from R1 regarding completing the Extreme Temperature
Assessment at least once every five calendar years and appending it to R8.
Regarding R5, the TP and PC should already possess steady state voltage criteria to satisfy TPL-001 R5. As a result, AEP recommends
removing R5 to avoid compliance risk associated with duplicative obligations. If the drafting team chooses to retain R5, the phrase “shall
have criteria for acceptable System steady state voltage limits and post-Contingency voltage deviations” might benefit from something
more actionable than “shall have.” AEP recommends the drafting team consider “shall devise” or “shall develop.”
R6’s identification of instability, uncontrolled separation, and cascading per criteria or methodology is already required in TPL-001 R6,
which once again appears duplicative and would unnecessarily increase compliance risk. AEP recommends it be removed.
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Response
Thank you for your comments. The DT does not find R3 and R4 to be duplicative. R3 is to draft out your process and R4 is to use the
process developed to establish category P0 as the normal System condition in Table 1.
The DT originally had the five year statement further down in the requirement language; however, received multiple comments over the
standards development process that the five year understanding needed to be made clear up front in the standard, which is why it has
been added to Requirement R1.
R5 and R6. These are addressing FERC Order 896 and the focus of TPL-008 is on extreme heat and extreme cold temperature conditions,
which may land differently from what is determined under TPL-001. In addition, FERC Order 896 explains that TPL-001 does not address
all the concerns causing blackouts.
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
Document Name
Comment
The below comment was provided previously for R2.
NERC's consultant uses BA load weighting (based on notes and conversations provided in the 9/10 TPL-008 presentation). As a result, this
weighting practice does not appear to directly meet this proposed R2.2 language regarding the most extreme events for a region. The
temperature may not actually be representative of “across the zone” because of this weighting. Of reliability considerations, load is
certainly part of the need, but potential impacts to generation and the connecting transmission, which may be in other regions, are also
important pieces to the delivery of resource to load. Removal or modification of this R2 ‘most extreme’ language is recommended; or
exempting the NERC library from needing to follow these criteria. Alternately, the SDT may modify to allow weighting to be used in
method.
Because the NERC Extreme Weather Event library is only updated every 3 years in the current plan, it is possible that an event in the
library would contain events that would not meet these R2 criteria for event “freshness”. The SDT may wish to consider modifying the
language regarding time, or an additional clause, to permit events currently in the NERC Extreme Weather Event library to not be subject
to the selection criteria currently in R2, or that entities may use the other criteria to evaluate and select other events.
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The below comment was provided previously for R3-R4.
In FERC Order 896, paragraph 39, there is a Commission Determination as follows:
“We also direct NERC to include in the Reliability Standard the framework and criteria that responsible entities shall use to develop from
the relevant benchmark event planning cases to represent potential weather-related contingencies (e.g., concurrent/correlated generation
and transmission outages, derates) and expected future conditions of the system such as changes in load, transfers, and generation
resource mix, and impacts on generators sensitive to extreme heat or cold, due to the weather conditions indicated in the benchmark
events. Developing such a framework would provide a common design basis for responsible entities to follow when creating benchmark
planning cases. This would not only help establish a clear set of expectations for responsible entities to follow when developing benchmark
planning events, but also facilitate auditing and enforcement of the Standard.”
In review of Order 896, we find the term “contingencies” is used two different ways. Paragraph 39 describes things that are in the base or
N-0 state – for example, a cold weather event occurs, and certain wind generators can no longer operate – this as a base contingency.
Similarly, in paragraph 88, there is an additional Commission Determination as follows, in further support of these baseline “contingency”
outages:
“Pursuant to section 215(d)(5) of the FPA, we adopt the NOPR proposal and direct NERC to require under the new or revised Reliability
Standard the study of concurrent/correlated generator and transmission outages due to extreme heat and cold events in benchmark
events as described in more detail below.”
Then later, in Paragraph 92 (still under the Commission Determination), FERC further clarifies:
“Regarding the comments of NYISO and EPRI on the difference between extreme events and contingencies covered under Reliability
Standard TPL-001-5.1, we clarify that all contingencies included in benchmark planning cases under the new or modified Reliability
Standard will represent initial conditions for extreme weather event planning and analysis. These contingencies (i.e.,
correlated/concurrent, temperature sensitive outages, and derates) shall be identified based on similar contingencies that occurred in
recent extreme weather events or expected to occur in future forecasted events.”
From these, it is clear that Order 896 is expecting “contingencies” of weather-based equipment outages to be part of the base or N-0
system state. The more traditional “contingencies” are then addressed on top of this condition, as presented in Order 896, Section G,
starting at Paragraph 95.

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The specific request from this comment is for the SDT to clarify how it expects such base “contingencies” to be included in the model.
There does not appear to be language currently in the standard in support of this, and it is clear from Order 896 that it is expected both
the base model outage “contingencies” and then subsequent contingency events to test system performance.
The SDT responded to this in its version 3 comment response:
“The SDT drafted Requirement R4 to require the responsible entity to use data consistent with Reliability Standard MOD-032,
supplemented by other sources as needed, for developing benchmark planning cases that represent System conditions based on selected
benchmark temperature events. This aligns with directives in FERC Order No. 896, paragraph 30, emphasizing the requirement of
developing both benchmark planning cases and sensitivity study cases. Requirement R4 is consistent with Reliability Standard TPL-001-5.1
in cross-referencing Reliability Standard MOD-032, which establishes consistent modeling data requirements and reporting procedures for
the development of planning horizon cases necessary to support analysis of the reliability of the interconnected System. It is also
consistent with Reliability Standard TPL-001-5.1 in acknowledging that data from other sources may be required to supplement the data
collected through Reliability Standard MOD-032 procedures.”
The original comment was not related at all to MOD-032 data. FERC is expecting NERC to develop a standard to build extreme weather
cases, and as part of those cases, FERC is requiring that in the base N-0 condition also include “weather-related contingencies (e.g.,
concurrent/correlated generation and transmission outages, derates)”. The current draft of TPL-008 does not mention outages, de-rates,
or generator availability due to extreme weather in its R3 or R4 language. R3.2 simply includes “Forecasted seasonal and temperature
dependent adjustments for Load, generation, Transmission, and transfers within the zone.” And R3.3 similar “Assumed seasonal and
temperature dependent adjustments for Load, generation, Transmission, and transfers in areas outside the zone, as needed.”, but
language for “weather-related contingencies (e.g., concurrent/correlated generation and transmission outages, derates)” from Order 896
is absent from the standard in its current form. This language should be added, likely to R3.2 and R3.3 because it conveys powerful root
concept of unexpected equipment outages and limitations in the base state due to extreme weather. If it is the SDT’s intention that
entities will review Order 896 and conclude that such concurrent outages are to be covered by a ‘supplemented by other sources as
needed’ clause, this is not the case. The standard needs to include language for entities to consider how such extreme weather related
concurrent/correlated outages are to be included in the base case.
The below comment was provided previously for R9.
In Order 896, FERC’s Commission determination in paragraph 157 reads:
“As stated above, we adopt and modify the NOPR proposal and direct NERC to require in the new or modified Reliability Standard the
development of corrective action plans that include mitigation for specified instances where performance requirements for extreme heat
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and cold events are not met—i.e., when certain studies conducted under the Standard show that an extreme heat or cold event would
result in cascading outages, uncontrolled separation, or instability.”
FERC’s directive is when the outcome of studies would result in cascading outages, uncontrolled separation, or instability, a corrective
action plan is required. However, in TPL-008, the SDT has gone further. The current state of draft TPL-001-8 R9 states:
“Each responsible entity, as identified in Requirement R1, shall develop a Corrective Action Plan(s) when the analysis of a benchmark
planning case, in accordance with Requirement R8 Part 8.1, indicates its portion of the Bulk Electric System is unable to meet performance
requirements for category P0 or P1 in Table 1. For each Corrective Action Plan, the responsible entity shall:”
The difference here is Order 896 is only requiring corrective action plans for cascading outages, uncontrolled separation, or instability. the
SDT is proposing to require corrective action plans for not meeting performance criteria, which also includes normal voltage limits or
normal line ratings, even though these exceedances may not result in cascading outages, uncontrolled separation, or instability. The
request is for the SDT to align its R9 language with Order 896 paragraph 157 language. These other limits are needed to assess for
cascading outages, uncontrolled separation, or instability, but the requirement to develop a corrective action plan for such exceedances is
beyond Order 896’s request for this proposed standard.
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Thank you for your comments.
Sub-parts of Requirement R2 are how the ERO completed the benchmark temperature events. Should an entity not agree with what has
been provided, you are welcome to work with other PCs within your zone to develop your own extreme heat and extreme cold
benchmark temperature events. All events in the ERO library will follow suit of Requirement R2. Should something change, it will go
through the standards development process and update TPL-008 standard accordingly.
A process has been developed to provide entities with the iterative process on how benchmark events will be updated every five years.
The process is a separate document from the TPL-008-1 Standard as some of the specifics are not appropriate nor requirements of the
TPL-008-1 Standard. For PCs who wish to work with other PCs to develop their own benchmark events should follow the additional
requirement language added to Requirement R2. This provides the boundaries entities must follow should the events provided by the
ERO not be adequate for Planning Coordinators to consider.
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The DT does not agree that it went beyond the FERC Order.
Cain Braveheart - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
BPA understands the complexities of drafting technically sound standards and appreciates the SDT's efforts through the multiple postings
of this project.
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Thank you.
Broc Bruton - Broc Bruton On Behalf of: Byron Booker, Oncor Electric Delivery, 1; - Broc Bruton
Answer
Document Name
Comment
No Comment
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Kevin Conway - Western Power Pool - 4
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Answer
Document Name
Comment
The Western Power Pool would like to thank the Drafting Team for working hard to find consensus. We understand the challenges the
Drafting Team faces in meeting the expectations of a number of different organizations across North America.
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Thank you.
Joshua London - Eversource Energy - 1, Group Name Eversource
Answer
Document Name
Comment
Requirement 3 –
Eversource recommends reinserting “Transmission Planner” or the phrase used in R4 “Each responsible entity, as identified in
Requirement R1” as part of the coordination in R3. The DT stated in its Consideration of Comments that “Coordination is at the PC level
and not at the TP level.” Eversource agrees this to be true for developing the Temperature Events but disagrees in regards to
implementing a process for developing planning cases. If the TPs are going to be expected to have a role in completing the Extreme
Temperature Assessment as stated in Requirement 1, they should participate in implementing a process for the development of cases.
Each Planning Coordinator shall coordinate with all Planning Coordinators and Transmission Planners within each of its zone(s)…; or
Each Planning Coordinator shall coordinate with all Planning Coordinators and with each responsible entity, as identified in Requirement
R1, within each of its zone(s)…;
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Thank you for your comments. Coordination is at the PC level and not the TP level. The PC and TP can coordinate together via
Requirement R1 and the TP can provide input. There are mechanisms for the TP to get involved.
Daniela Atanasovski - APS - Arizona Public Service Co. - 1
Answer
Document Name
Comment
None
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Mark Garza - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE Voter
Answer
Document Name
Comment
FirstEnergy has no additional comments.
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Thank you.
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Donna Wood - Tri-State G and T Association, Inc. - 1
Answer
Document Name
Comment
NA
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE continues to underscore that the Standard Requirements, as currently stated, do not appear to require assessing the impact of
concurrent failures of the Bulk Power System generation and transmission equipment that are typically experienced during extreme heat
or cold weather conditions. FERC Order No. 896 states: “…the impact of concurrent failures of Bulk-Power System generation and
transmission equipment and the potential for cascading outages that may be caused by extreme heat and cold weather events should be
studied”. The Considerations of the Order document says “Per Requirement R4, the data necessary to build the benchmark planning
cases must be provided via MOD-032 and supplemented by other sources as needed. Any concurrent/correlated generator and
transmission outages due to extreme heat and cold events in benchmark temperature events should be reflected in the model data and
thus represented in the initial conditions of the benchmark planning cases.”

Based on the current Requirements R3 and R4 language, the cases could be built with high loads and high generation dispatch for the
extreme weather without including concurrent outages. Therefore, a requirement in R3 or R4 that specifically says to include
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“concurrent” generator and transmission outages in the initial conditions of the benchmark planning cases needs to be added in
accordance with the FERC Order. Also, the rationale for those concurrent outages selected for the initial conditions shall be available as
supporting information. Texas RE noticed that the Technical Rationale does mention concurrent outages and recommends incorporating
this language directly into the requirement language itself through the note described below.

Texas RE suggests either requiring the basic assumptions described in R3 to include, at minimum, the severe contingencies or outages
experienced within each Transmission Planner’s respective area during the most extreme conditions to be modeled in the benchmarking
cases. Texas RE recommends the following language for Requirement R3:
3.5 The most severe continencies experienced in each Transmission Planner’s respective area during a historical most extreme conditions
shall be documented and modeled in the benchmark planning case(s).
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Thank you for your comments. Transmission Planner are not the best qualified entity to provide this information, which is why the
standard points to MOD-0032, which is provided by the Generator Owner.
Stephen Stafford - Stephen Stafford On Behalf of: Greg Davis, Georgia Transmission Corporation, 1; - Stephen Stafford
Answer
Document Name
Comment
Comments: GTC has provided the below recommendations in previous ballots, however, it appears that the SDT has not considered
revising the proposed standard to address, therefore, these concerns/recommendations are still considered valid by GTC.
R4:

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• The SDT should consider removing R4.2, since the assessment already covers multiple extreme weather scenarios. There is
questionable reliability benefit in running additional sensitivities that do not rise to the level of requiring (or eliminating) corrective
actions.
R5:
• The recently adopted NERC Glossary term, System Voltage Limits, should be referenced in this requirement instead of the outdated
wording “System steady state voltage limits”. “…shall have criteria for acceptable System Voltage Limits …”
• Since this requirement appears to refer to steady-state voltage, the post contingency voltage deviation portion of the existing
requirement should be removed. The resultant steady-state voltage level being outside of acceptable high and low limits is the point of
concern. For example, if a low voltage criterion is 0.92 p.u., then voltages below this limit would violate this particular criterion regardless
of whether the beginning voltage was 0.95 p.u., 0.98 p.u., or any other voltage level.
R6:
• The inclusion of “within an Interconnection” is not appropriate as the PC or TP should not be required to assess outside of its
applicable area. Note the inclusion of more appropriate language referring to the PC’s or TP’s planning area (its portion of the Bulk
Electric System) in this draft so it is not clear why some requirements refer to an Interconnection while others, more correctly, refer to
the area of actual responsibility for the PC or TP.
• The following bullet contains a wording addition to clarify the applicability of this requirement to System-wide impacts. This is also
consistent with wording in other Reliability Standards when referencing these types of impacts.
• “Each responsible entity, as identified in Requirement R1, shall define and document the criteria or methodology used in the
Extreme Temperature Assessment analysis to identify instability, uncontrolled separation, or Cascading of the Bulk Electric System.”
R8:
• It is unclear if the responsible entity must identify continencies for each event type shown within each category, or only those
event types that are expected to produce more severe System impacts on its portion of the Bulk Electric System
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Response
Thank you for your comments.
Requirement R43 is in response to FERC Order 896, which requires sensitivities.
System Voltage Limits: The DT determined “System Voltage Limits” focuses on operations and planning information and differs from what
is used in the standard. The DT concluded to maintain the proposed language consistent with Reliability Standard TPL-001-5.1.
R6. DT felt it was important to clarify in certain areas of the standard where it is within the interconnection focused. zone differences.
R8. This is similar to how completed entities complete what is needed in TPL-001, but for TPL-008, which should not be new on how to
complete. In addition, see R7.
Anna Martinson - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO Group
Answer
Document Name

2023-07_Unofficial_Comment_Form Draft_4_110724_MRO.docx

Comment
Requirement R3 indicates forecasting Load, generation, and Transmission. There are significant barriers to modeling Load and generation
based upon temperatures, notably forecasting out into the long-term planning timeframes. With that said, the MRO NSRF recommends
that the NERC and drafting team develop implementation guidance and/or a reliability guideline to ensure Planning Coordinators can
meet the requirements in the R3 section.
Several terms in the TPL-008-1 ERO Benchmark Weather Event Development and Maintenance Process DRAFT indicated defined terms
are located in the glossary of terms, yet these terms are not defined in the glossary of terms. The term Zoneal is used rather than the
term Zonal. There are also acronyms that do not represent the words spelled, for example it lists Affected Zonal Entity as ARE rather than
the more representative term AZE.

Definitions Refer to the NERC Glossary of Terms3 for the below capitalized terms used in this process.
• Affected Zoneal Entity (ARE)
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• Compliance Enforcement Authority (CEA)
• Coordinated Oversight
• Extreme Temperature Assessment (ETA)
• Lead Zoneal Entity (LRE)
• Multi-Zone Registered Entity (MRRE)
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Scott Brame, N/A, Brame Scott
0

Response
Thank you for your comments.
Please see the updated ERO Benchmark Event Process.
Information is collected through MOD-032 and the process should not be different from what is completed to-date.
Please see updated benchmark event process document.
Adrian Andreoiu - BC Hydro and Power Authority - 1, Group Name BC Hydro
Answer
Document Name
Comment
1. Requirement R1 as drafted includes two separate requirements, i.e. to (1) identify responsibilities amongst applicable PCs and TPs, and
(2) complete an Extreme Temperature Assessment every five years.
BC Hydro suggests that these are separate objectives and recommends that this Requirement be split to reflect these accordingly for
enforceability (e.g. incident severity level), and cause-based incident monitoring.
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2. BC Hydro’s understanding is that in order to determine the Contingencies that have a more severe impact per R7, the ETA needs to
account for all contingencies within the identified zone(s), and not just those within its portion of the BES. Please confirm or provide
additional clarity as appropriate.
3. Requirement R4 and the associated VSL Levels reference “the coordination process developed in Requirement R3”. R3 requires a
benchmark planning cases development process, it does not require a coordination process.
BC Hydro recommends Recommend revising R4 and the associated VSL Levels for clarity and consistency.
BC Hydro also recommends that the language of R3 be revised to read “to implement a documented process” rather than “to implement
a process”.
4. The VSL Table for Requirement R1 indicates a Severe Level if an entity “failed to identify individual and joint responsibilities”. There are
no other Severity Levels associated with responsibilities identification, which is conducive to an interpretation that failing to identify even
one of the R2 through R11 associated responsibility would be classified as a Severe VSL. BC Hydro suggests that failing to identify one or
less than the full set of responsibility should carry less Severity Levels, and recommends that this be reflected in the lower Severity Levels
as well.
5. The High and Severe VSL Levels for Requirement R8 are based on an entity’s failing to evaluate the results of the sensitivity (High VSL)
and benchmarking cases (Severe VSL). R8 and its associated M8 do not explicitly require that an evaluation be also retained as evidence
of compliance, in addition to the results documentation.
BC Hydro recommends that the R8, M8 and corresponding VSL Levels be revised for consistency.
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Thank you for your comments.
1. The DT feels it is adequate to let the have entities identify responsibilities and that five years up front. The DT strategically put this
into R1 as it applies to all requirements following R1.
2. The contingencies requirement are for your portion of the BES. If an entity wants to run contingencies outside its zone, it is not
required based on R7.
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3. Please see the updated VSL for Requirement R4.
4. R1 is a binary drafted requirement on responsibilities. (pass/fail requirement). A binary requirement is a “pass or fail” type
requirement where any degree of noncompliant performance would result in totally or mostly missing the reliability intent of the
requirement.
5. Please see updated VSL for Requirement R8.
Allie Gavin - Allie Gavin On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Allie Gavin
Answer
Document Name
Comment
•

•

•

•

ITC believes that the Yes for NCLL for P0 Sensitivity Cases should be changed to No. If it is deemed important to analyze a
sensitivity case, the system should be able to serve firm load both for system normal and for single contingencies. With the
requirements left as proposed, entities would need to proactively start shedding load for changes in generation, real and reactive
forecasted Load, or transfers. System Operators will be forced to rely on preventative load shed during long term construction
outages when experiencing extreme weather as it is highly likely that these will not be able to be cancelled.
ITC believes that the Yes allowing for NCLL for P1 Base and Sensitivity Cases should be changed to No. ITC believes that a reliable
system should be able to serve firm load for system normal and for single contingencies. Utilities typically schedule long term
construction outages during winter (off-peak) and then experience extreme temperature scenarios. System Operators will need to
rely on preventative load shed during these long term construction outages, that could not be cancelled if entities include NCLL as
part of their corrective action plan.
ITC suggests that Footnote 6 (Page 12) include a clarification that Non Consequential Load Loss shall not be the only element in
a Corrective Action Plan. See below:
o Benchmark planning cases require the development of a Corrective Action Plan when the responsible entity’s portion of
the BES is unable to meet the performance requirements for categories P0 or P1. Additionally, in benchmark planning
cases, Non-Consequential Load Loss is not permitted for category P0 and Non Consequential Load Loss shall not be the
only element of a Corrective Action Plan unless approved by applicable regulatory authorities or governing bodies
responsible for retail electric service issues. See Requirement R9 for the relevant requirements.
Specify if temperature is F or C on benchmark table of events. Clarify and specify timing on standard on when they will review the
benchmark events.

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•

In DRAFT ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance Standards
Development and Engineering Process Document October 2024, ITC suggests moving footnote 4 page 2 into the Process Overview
and clarify if these actions will happen every cycle, or just the first iteration.

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Thank you for your comments.
Sensitivity cases (change from yes to no). Load, generation transfer would be more extreme than what is expected from TPL-001, etc. and
needs to remain as yes in the table of TPL-008-1.
Additional elements are allowed within your CAPs, but the standard has been drafted in consensus with industry regarding this matter.
Industry disagrees based on previous comments with requiring more of entities based on feedback. The team feels we are in a good
position to date.
See updated process document and review the TPL-008-1 Read Me Document. This explains that temperature is F. Link to document: TPL008_Data_Library_Read_Me.pdf
Casey Perry - PNM Resources - 1,3 - WECC,Texas RE
Answer
Document Name
Comment
No additional comments.
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Daniel Gacek - Exelon - 1, Group Name Exelon
Answer
Document Name
Comment
Below are a few additional comments or questions for the drafting team to consider:
1. Clarify what “long-term transmission planning horizon” is in Requirement 3.1, which is the target time horizon for this standard.
Currently NERC definition indicates year 6-10 or beyond. From our understanding, our PC intends to align with LTRTP.
2. Based on our interpretation, a benchmark temperature event doesn’t have to be a historical event. Is that correct?

Likes

0

Dislikes

0

Response
Thank you for your comments.
R3 time horizon is long term planning focuses on 6-10 years.
Historical event: benchmark event by definition has to be a historical event. However, if you are able to meet Requirement R2 and
complete other events beyond historical events, that would be permitted.
Greg Sorenson - Greg Sorenson On Behalf of: Tremayne Brown, ReliabilityFirst , 10; - Greg Sorenson
Answer
Document Name
Comment
Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

117

RF appreciates the efforts of the Standards Drafting Team to apply comments received.
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 NPCC RSC
Answer
Document Name
Comment
NPCC RSC agrees with the changes proposed by the standard drafting team.
Likes

0

Dislikes

0

Response
Thank you for your support.
Andy Thomas - Duke Energy - 1,3,5,6 - SERC,RF
Answer
Document Name
Comment
None.
Likes
Dislikes

0
0

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

118

Response
Hayden Maples - Hayden Maples On Behalf of: Jeremy Harris, Evergy, 3, 5, 1, 6; Kevin Frick, Evergy, 3, 5, 1, 6; Marcus Moor, Evergy, 3,
5, 1, 6; Tiffany Lake, Evergy, 3, 5, 1, 6; - Hayden Maples
Answer
Document Name
Comment
Evergy supports and incorporates by reference the comments of the Midwest Reliability Organization's NERC Standards Review Forum
(MRO NSRF) on question 5
Likes

0

Dislikes

0

Response
Please see the DT’s response to MRO NSRF.
Helen Lainis - Independent Electricity System Operator - 2, Group Name IRC SRC
Answer
Document Name
Comment
The IRC SRC is concerned that Requirement R3 unnecessarily and inadvertently limits the ability of entities to properly develop their
benchmark planning cases. Specifically, the IRC SRC is concerned that R3 could be understood to mean that entities are limited to making
the adjustments specifically described in R3 and are prevented from making adjustments necessary to ensure that the generation
necessary to serve load is available so that the case can solve. As the drafting team recognizes in the Technical Rationale, adjusting the
case to ensure that it contains enough generation to serve the modeled load is essential to ensure that the standard does not stray into
the realm of resource adequacy issues and fully complies with paragraph 94 of FERC Order No. 896, which states that resource adequacy
is not in scope for this project. While the IRC SRC appreciates this recognition, the Technical Rationale is not a binding document, and
Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

119

future revisions to the standard may introduce additional ambiguity regarding what types of adjustments are permissible under
Requirement R3.
To clarify the standard and better position it for future revisions, the IRC SRC recommends that the drafting team revise Part 3.2 by
replacing the period at the end of Part 3.2 with the following: “, provided that the responsible entity may adjust the total modeled
generation or Load in each case as necessary to allow the total modeled generation to serve the total modeled System Load.”
The IRC SRC also recommends that Requirement R4 be revised as needed to align with any revisions made to Requirement R3.
In addition, the IRC SRC requests that the ERO develop a Reliability Guideline for this proposed standard, and in particular, for
Requirement R3 showing how a Planning Coordinator would adjust the benchmark planning case to ensure that it contains enough
generation necessary to serve load.
Likes

0

Dislikes

0

Response
Thank you for your comments.
R3. Guidance has been provided in the TR as mentioned in your comments and does not feel additional language is needed within the
standard. Therefore, the team does not agree to make the changes requested for Requirement R4.
Kennedy Meier - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment
ERCOT joins the comments submitted by the IRC SRC for this question and adopts them as its own.
Likes

0

Dislikes

0

Response
Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

120

Please see the DT’s response to IRC SRC.
Gregory Campoli - New York Independent System Operator - 2
Answer
Document Name
Comment
The NYISO would like to confirm that is it acceptable to use additional (beyond those directed in Requirement 2) weather metrics to
identify the benchmark temperature events. For example, summer extreme conditions could include a temperature-humidity index which
integrates temperature and humidity and is shown to be a more robust predictor of peak loads than temperature alone. Likewise, winter
extreme conditions could include a wind component (i.e., a wind-chill index). In either case, the associated temperature value could
easily be extracted, as necessary, for any follow-on analysis (e.g., line ratings) requiring temperature specifically.
The NYISO would like to confirm that is it acceptable to use additional (beyond those directed in Requirement 2) averaging mechanisms
which have been demonstrated to be robust predicators of extreme peak loads. For example, the NYISO currently employs a three-day
weighted average temperature index for summer conditions and a three-day weighted average of a temperature-wind index variable for
winter conditions.
The NYISO would like to confirm that is it acceptable to leverage their own knowledge and expertise in constructing the specific extreme
heat and cold temperature events to be studied, within reasonable constraints, such as the 40-year historic period.
Likes

0

Dislikes

0

Response
Thank you for your comments.
As long as you meet the requirement of R2 and its sub parts, you are welcome to consider other components.
PCs can develop their own benchmark events with other PCs within its zone if they do not want to select from the ERO benchmark event
library.
Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

121

Shannon Mickens - Shannon Mickens On Behalf of: Joshua Phillips, Southwest Power Pool, Inc. (RTO), 2; - Shannon Mickens, Group
Name SPP RTO
Answer
Document Name
Comment
Another concern for SPP is applicable to the model not being able to solve which includes the sensitivity (stability cases for P0 condition).
It is unclear on the expectation of the drafting team in reference to the PC not being able to solve the models for the various categories of
the ETA. Also, there are concerns around gathering and aligning the appropriate temperature data independently.
Requirement R3 indicates forecasting Load, generation, and Transmission. There are significant barriers to modeling Load and generation
based upon temperatures, notably forecasting out into the long-term planning timeframes. With that said, SPP recommends that the
NERC and drafting team develop implementation guidance and/or a reliability guideline to ensure Planning Coordinators are able to meet
the requirements in the R3 section.
Likes

0

Dislikes

0

Response
Thank you for your comments. The DT feels this request is asking for too prescriptive language within the standard. The goal of a standard
is to tell an entity what and sometimes when, but not the how. Flexibility is up to the entities on how to address the standards based on
regional differences across the US.
Jennifer Bray - Arizona Electric Power Cooperative, Inc. - 1
Answer
Document Name
Comment
Thank you for the opportunity to comment.
Likes

0

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

122

Dislikes

0

Response
Thank you.
Bob Cardle - Bob Cardle On Behalf of: Marco Rios, Pacific Gas and Electric Company, 3, 1, 5; Sandra Ellis, Pacific Gas and Electric
Company, 3, 1, 5; Tyler Brun, Pacific Gas and Electric Company, 3, 1, 5; - Bob Cardle
Answer
Document Name
Comment
The DT should highly consider or leave it to Planning Coordinator’s discretion when it comes to sensitivities: PC’s should be given the
opportunity/flexibility in determining whether sensitivities are needed or as to how much study is needed regarding sensitivities.
Likes

0

Dislikes

0

Response
Thank you for your comment. The DT addresses what is required of FERC Order 896.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
OPG supports NPCC Regional Standards Committee’s comments.
Likes

0

Dislikes

0

Response
Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

123

Thank you for your support.
Amy Wilke - American Transmission Company, LLC - 1
Answer
Document Name
Comment
While ATC has voted in support of approving project 2023-07; we are also in support of the comments provided by the MRO NSRF.
Likes

0

Dislikes

0

Response
Thank you for your support. Please see the DT’s response to MRO NSRF.
End of Report

Consideration of Comments | Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather
December 2, 2024

124

Reminder
Standards Announcement

Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather
Additional Ballots and Non-binding Poll Open through November 21, 2024
Now Available

Additional ballots for draft four of TPL-008-1 – Transmission System Planning Performance
Requirements for Extreme Temperature Events and non-binding poll of the associated Violation
Risk Factors and Violation Severity Levels are open through 8 p.m. Eastern, Thursday, November
21, 2024.
The Standards Committee approved waivers to the Standards Process Manual at their December
2023 meeting. These waivers were sought by NERC Standards for reduced formal comment and
ballot periods to assist the drafting teams in expediting the standards development process due to
firm timeline expectations set by FERC Order 896.
The standard drafting team’s considerations of the responses received from the last comment
period are reflected in this draft of the standard.
Reminder Regarding Corporate RBB Memberships

Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more
than the one permitted representative in a particular Segment must withdraw the duplicate
membership(s) prior to joining new ballot pools or voting on anything as part of an existing ballot
pool. Contact [email protected] to assist with the removal of any duplicate registrations.
Balloting

Members of the ballot pools associated with this project can log in and submit their votes by accessing
the Standards Balloting and Commenting System (SBS) here.
Note: Votes cast in previous ballots, will not carry over to additional ballots. It is the responsibility of
the registered voter in the ballot pools to place votes again. To ensure a quorum is reached, if you do
not want to vote affirmative or negative, cast an abstention.
•

Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.

RELIABILITY | RESILIENCE | SECURITY

•

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 ballot results will be announced and posted on the project page. The drafting team will review all
responses received during the comment period and determine the next steps of the project.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Jordan Mallory (via email) or at
404-479-7358. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists"
from the "Service" drop-down menu and specify “Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather observer list” in the Description Box.

North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Ballot Open Reminder
Project 2023-07 Transmission Planning Performance Requirements for Extreme Weather | November 21, 2024

2

Public

Standards Announcement

Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather
Formal Comment Period Open through November 21, 2024
Now Available

A 15-day formal comment period for draft four of TPL-008-1 – Transmission System Planning
Performance Requirements for Extreme Temperature Events is open through 8 p.m. Eastern,
Thursday, November 21, 2024.
The Standards Committee approved waivers to the Standards Process Manual at their December
2023 meeting. These waivers were sought by NERC Standards for reduced formal comment and
ballot periods to assist the drafting teams in expediting the standards development process due to
firm timeline expectations set by FERC Order 896.
The standard drafting team’s considerations of the responses received from the previous comment
period are reflected in this draft of the standard.
Reminder Regarding Corporate RBB Memberships

Under the NERC Rules of Procedure, each entity and its affiliates is collectively permitted one voting
membership per Registered Ballot Body Segment. Each entity that undergoes a change in corporate
structure (such as a merger or acquisition) that results in the entity or affiliated entities having more than
the one permitted representative in a particular Segment must withdraw the duplicate membership(s)
prior to joining new ballot pools or voting on anything as part of an existing ballot pool. Contact
[email protected] to assist with the removal of any duplicate registrations.
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. An unofficial Word
version of the comment form is posted on the project page.
•

Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.

•

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

Public

Next Steps

Additional ballots for the standard and implementation plan, as well as a non-binding poll of the
associated Violation Risk Factors and Violation Severity Levels will be conducted November 12-21,
2024.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Jordan Mallory (via email) or at
404-479-7358. Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists"
from the "Service" drop-down menu and specify “Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather observer list” in the Description Box.

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 2023-07 Transmission Planning Performance Requirements for Extreme Weather | November 7, 2024

2

NERC Balloting Tool (/)

Dashboard (/)

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS  
Comment: View Comment Results (/CommentResults/Index/355)
Ballot Name: 2023-07 Transmission Planning Performance Requirements for Extreme Weather TPL-008-1 AB 4 ST
Voting Start Date: 11/12/2024 12:01:00 AM
Voting End Date: 11/21/2024 8:00:00 PM
Ballot Type: ST
Ballot Activity: AB
Ballot Series: 4
Total # Votes: 261
Total Ballot Pool: 314
Quorum: 83.12
Quorum Established Date: 11/21/2024 3:56:05 PM
Weighted Segment Value: 73.71
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

89

1

44

0.698

19

0.302

0

16

10

Segment:
2

8

0.8

6

0.6

2

0.2

0

0

0

Segment:
3

68

1

37

0.74

13

0.26

0

7

11

Segment:
4

18

1

7

0.636

4

0.364

0

2

5

Segment:
5

76

1

28

0.667

14

0.333

0

14

20

Segment:
6

47

1

24

0.75

8

0.25

0

8

7

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

1

0

0

0

0

0

0

1

0

Segment

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

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:
9

0

0

0

0

0

0

0

0

0

Segment:
10

7

0.7

7

0.7

0

0

0

0

0

Totals:

314

6.5

153

4.791

60

1.709

0

48

53

Segment

BALLOT POOL MEMBERS
Show

All

Segment

entries

Organization

Search:

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power,
Inc.

Hillary Creurer

Affirmative

N/A

1

Ameren - Ameren
Services

Tamara Evey

None

N/A

1

American Transmission
Company, LLC

Amy Wilke

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Daniela
Atanasovski

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Jennifer Bray

Affirmative

N/A

1

Associated Electric
Cooperative, Inc.

Mark Riley

Affirmative

N/A

1

Austin Energy

Thomas
Standifur

Affirmative

N/A

Affirmative

N/A

1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Corporation

Segment

Organization

Voter

1

Balancing Authority of
Northern California

Kevin Smith

1

BC Hydro and Power
Authority

1

Designated
Proxy

NERC
Memo

Affirmative

N/A

Adrian Andreoiu

Negative

Comments
Submitted

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

Affirmative

N/A

1

Black Hills Corporation

Travis
Grablander

Affirmative

N/A

1

Bonneville Power
Administration

Kamala RogersHolliday

Affirmative

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Negative

Comments
Submitted

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

None

N/A

1

Central Iowa Power
Cooperative

Kevin Lyons

Negative

Third-Party
Comments

1

City Utilities of Springfield,
Missouri

Michael Bowman

Negative

Third-Party
Comments

1

Colorado Springs Utilities

Corey Walker

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dairyland Power
Cooperative

Karrie Schuldt

Negative

Third-Party
Comments

1

Dominion - Dominion
Virginia Power

Steven Belle

Affirmative

N/A

1

Duke Energy

Katherine Street

Affirmative

N/A

1

Edison International Southern California
Edison Company

Robert Blackney

Affirmative

N/A

1

Entergy

Brian Lindsey

None

N/A

1

Evergy

Kevin Frick

Affirmative

N/A

Negative

Comments
Submitted

1 - NERC Ver 4.2.1.0
Eversource
Energy
Joshua London
© 2024
Machine
Name: ATLVPEROWEB01

Tim Kelley

Ballot

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

John Martinez

Affirmative

N/A

1

Georgia Transmission
Corporation

Greg Davis

Negative

Comments
Submitted

1

Glencoe Light and Power
Commission

Terry Volkmann

Negative

Third-Party
Comments

1

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Emma Halilovic

Lidija Efremova

Affirmative

N/A

1

Hydro-Quebec (HQ)

Nicolas Turcotte

Chantal Mazza

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Sean Steffensen

None

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Denise Sanchez

Affirmative

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Allie Gavin

Affirmative

N/A

1

JEA

Joseph McClung

Affirmative

N/A

1

KAMO Electric
Cooperative

Micah Breedlove

Affirmative

N/A

1

Lakeland Electric

Larry Watt

None

N/A

1

Lincoln Electric System

Josh Johnson

Abstain

N/A

1

Long Island Power
Authority

Isidoro Behar

Abstain

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Abstain

N/A

1

Lower Colorado River
Authority

Matt Lewis

Abstain

N/A

1

LS Power Transmission,
LLC

Jennifer
Richardson

Abstain

N/A

Affirmative

N/A

1

M and A Electric Power
William Price
Cooperative
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Stephen
Stafford

Segment

Organization

Voter

1

Manitoba Hydro

Nazra Gladu

1

MEAG Power

David Weekley

1

Minnkota Power
Cooperative Inc.

Theresa Allard

1

Muscatine Power and
Water

1

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Rebika Yitna

Abstain

N/A

Nikki CarsonMarquis

Negative

Third-Party
Comments

Andrew Kurriger

Abstain

N/A

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Jeffrey Streifling

Abstain

N/A

1

Nebraska Public Power
District

Jamison Cawley

Negative

Third-Party
Comments

1

New York Power Authority

Daniel Valle

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Negative

Comments
Submitted

1

NiSource - Northern
Indiana Public Service Co.

Alison Nickells

Negative

Comments
Submitted

1

Northeast Missouri
Electric Power
Cooperative

Brett Douglas

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Negative

Third-Party
Comments

1

Omaha Public Power
District

Doug Peterchuck

None

N/A

1

Oncor Electric Delivery

Byron Booker

Negative

Comments
Submitted

1

Orlando Utilities
Commission

Aaron Staley

None

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Negative

Third-Party
Comments

1

Pacific Gas and Electric
Company

Marco Rios

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Broc Bruton

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Platte River Power
Authority

Marissa Archie

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Affirmative

N/A

1

Portland General Electric
Co.

Brooke Jockin

Abstain

N/A

1

PPL Electric Utilities
Corporation

Michelle
McCartney
Longo

Affirmative

N/A

1

PSEG - Public Service
Electric and Gas Co.

Karen Arnold

Affirmative

N/A

1

Public Utility District No. 1
of Chelan County

Diane E Landry

Negative

Comments
Submitted

1

Public Utility District No. 1
of Snohomish County

Alyssia Rhoads

Affirmative

N/A

1

Public Utility District No. 2
of Grant County,
Washington

Joanne Anderson

Abstain

N/A

1

Sacramento Municipal
Utility District

Wei Shao

Tim Kelley

Affirmative

N/A

1

Salt River Project

Laura Somak

Israel Perez

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Abstain

N/A

1

SaskPower

Wayne
Guttormson

Abstain

N/A

1

Seminole Electric
Cooperative, Inc.

Kristine Ward

None

N/A

1

Sempra - San Diego Gas
and Electric

Mohamed
Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

Abstain

N/A

1

Sunflower Electric Power
Paul Mehlhaff
Corporation
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Segment

Organization

Voter

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

1

Tallahassee Electric (City
of Tallahassee, FL)

1

Designated
Proxy

NERC
Memo

Affirmative

N/A

Scott Langston

Abstain

N/A

Tennessee Valley
Authority

David Plumb

Negative

Comments
Submitted

1

Tri-State G and T
Association, Inc.

Donna Wood

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Abstain

N/A

1

Unisource - Tucson
Electric Power Co.

Jessica Cordero

Negative

Comments
Submitted

1

VELCO -Vermont Electric
Power Company, Inc.

Randall Buswell

Abstain

N/A

1

Western Area Power
Administration

Ben Hammer

Affirmative

N/A

1

Xcel Energy, Inc.

Eric Barry

None

N/A

2

California ISO

Darcy O'Connell

Affirmative

N/A

2

Electric Reliability Council
of Texas, Inc.

Kennedy Meier

Negative

Comments
Submitted

2

Independent Electricity
System Operator

Helen Lainis

Affirmative

N/A

2

ISO New England, Inc.

John Pearson

Affirmative

N/A

2

Midcontinent ISO, Inc.

Kirsten Rowley

Affirmative

N/A

2

New York Independent
System Operator

Gregory Campoli

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Thomas Foster

Elizabeth Davis

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Joshua Phillips

Shannon
Mickens

Negative

Comments
Submitted

3

AEP

Leshel Hutchings

Affirmative

N/A

Affirmative

N/A

3
Ameren - Ameren
David Jendras Sr
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Services

Jennie Wike

Ballot

Keith Jonassen

Danielle Moskop

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

APS - Arizona Public
Service Co.

Jessica Lopez

Affirmative

N/A

3

Arkansas Electric
Cooperative Corporation

Ayslynn Mcavoy

None

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

Lovita Griffin

Affirmative

N/A

3

Avista - Avista
Corporation

Robert Follini

Affirmative

N/A

3

BC Hydro and Power
Authority

Ming Jiang

Negative

Comments
Submitted

3

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Joseph Amato

Affirmative

N/A

3

Black Hills Corporation

Josh Combs

Affirmative

N/A

3

Bonneville Power
Administration

Ron Sporseen

Affirmative

N/A

3

Buckeye Power, Inc.

Tom Schmidt

None

N/A

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Affirmative

N/A

3

City Utilities of Springfield,
Missouri

Jessica
Morrissey

Negative

Third-Party
Comments

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

None

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Lincoln Burton

Affirmative

N/A

3

Dominion - Dominion
Virginia Power

Victoria Crider

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Marvin Johnson

Abstain

N/A

Affirmative

N/A

3

Duke Energy - Florida
Marcelo
Power Corporation
Pesantez
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Carly Miller

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Entergy

James Keele

None

N/A

3

Evergy

Marcus Moor

Affirmative

N/A

3

Eversource Energy

Vicki O'Leary

Negative

Comments
Submitted

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

None

N/A

3

Great River Energy

Michael
Brytowski

Negative

Third-Party
Comments

3

Imperial Irrigation District

George Kirschner

Affirmative

N/A

3

JEA

Marilyn Williams

Affirmative

N/A

3

Lakeland Electric

Steven Marshall

None

N/A

3

Lincoln Electric System

Sam Christensen

Abstain

N/A

3

Los Angeles Department
of Water and Power

Fausto Serratos

None

N/A

3

M and A Electric Power
Cooperative

Gary Dollins

Affirmative

N/A

3

Manitoba Hydro

Mike Smith

Affirmative

N/A

3

MEAG Power

Roger Brand

Abstain

N/A

3

MGE Energy - Madison
Gas and Electric Co.

Benjamin Widder

Negative

Third-Party
Comments

3

Muscatine Power and
Water

Seth Shoemaker

Abstain

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

Negative

Third-Party
Comments

3

Nebraska Public Power
Tony Eddleman
District
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Denise Sanchez

Rebika Yitna

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

New York Power Authority

Richard Machado

Affirmative

N/A

3

NextEra Energy - Florida
Power and Light Co.

Karen Demos

Negative

Comments
Submitted

3

NiSource - Northern
Indiana Public Service Co.

Steven
Taddeucci

Negative

Comments
Submitted

3

Northern California Power
Agency

Michael Whitney

None

N/A

3

NW Electric Power
Cooperative, Inc.

Heath Henry

Affirmative

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Negative

Third-Party
Comments

3

Omaha Public Power
District

David Heins

Negative

Third-Party
Comments

3

OTP - Otter Tail Power
Company

Wendi Olson

None

N/A

3

Pacific Gas and Electric
Company

Sandra Ellis

Negative

Comments
Submitted

3

Platte River Power
Authority

Richard Kiess

Affirmative

N/A

3

PNM Resources - Public
Service Company of New
Mexico

Amy
Wesselkamper

Affirmative

N/A

3

Portland General Electric
Co.

Mayra Franco

Abstain

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

Christopher
Murphy

Affirmative

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Negative

Comments
Submitted

3

Sacramento Municipal
Utility District

Nicole Looney

Tim Kelley

Affirmative

N/A

3

Salt River Project

Mathew Weber

Israel Perez

Affirmative

N/A

Abstain

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
3
Santee Cooper
Vicky Budreau

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Seminole Electric
Cooperative, Inc.

Usama Tahir

None

N/A

3

Sempra - San Diego Gas
and Electric

Bryan Bennett

Affirmative

N/A

3

Sho-Me Power Electric
Cooperative

Jarrod Murdaugh

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

Southern Indiana Gas and
Electric Co.

Ryan Snyder

Abstain

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

John Nierenberg

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Negative

Comments
Submitted

3

Tri-State G and T
Association, Inc.

Ryan Walter

Affirmative

N/A

3

Xcel Energy, Inc.

Nicholas Friebel

None

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Negative

Third-Party
Comments

4

Arkansas Electric
Cooperative Corporation

Jenni Sudduth

None

N/A

4

Austin Energy

Tony Hua

Affirmative

N/A

4

Buckeye Power, Inc.

Jason Procuniar

None

N/A

4

City Utilities of Springfield,
Missouri

Jerry Bradshaw

Negative

Third-Party
Comments

4

CMS Energy - Consumers
Energy Company

Aric Root

None

N/A

4

DTE Energy

Patricia Ireland

Abstain

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Joseph Gatten

Ryan Strom

Segment

Organization

Voter

4

Georgia System
Operations Corporation

Katrina Lyons

4

North Carolina Electric
Membership Corporation

Richard McCall

4

Northern California Power
Agency

Marty Hostler

4

Public Utility District No. 1
of Snohomish County

4

Designated
Proxy

Ballot

NERC
Memo

Negative

Third-Party
Comments

Scott Brame

Negative

Third-Party
Comments

Mason Jones

None

N/A

John D.
Martinsen

Affirmative

N/A

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Abstain

N/A

4

Sacramento Municipal
Utility District

Foung Mua

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

George Pino

None

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

Utility Services, Inc.

Carver Powers

Affirmative

N/A

4

Western Power Pool

Kevin Conway

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

AES - AES Corporation

Ruchi Shah

None

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

None

N/A

5

APS - Arizona Public
Service Co.

Andrew Smith

Affirmative

N/A

5

Associated Electric
Cooperative, Inc.

Chuck Booth

None

N/A

5

Austin Energy

Michael Dillard

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

None

N/A

5

BC Hydro and Power
Authority

Christine
Jennings

None

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Tim Kelley

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Berkshire Hathaway - NV
Energy

Dwanique Spiller

Affirmative

N/A

5

Black Hills Corporation

Sheila Suurmeier

Affirmative

N/A

5

Bonneville Power
Administration

Milli Chennell

Affirmative

N/A

5

Buckeye Power, Inc.

Kevin Zemanek

None

N/A

5

California Department of
Water Resources

ASM Mostafa

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

None

N/A

5

Colorado Springs Utilities

Jeffrey Icke

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

Michelle Pagano

Affirmative

N/A

5

Constellation

Alison MacKellar

Abstain

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

Dairyland Power
Cooperative

Tommy Drea

Negative

Third-Party
Comments

5

Dominion - Dominion
Resources, Inc.

Barbara Marion

Affirmative

N/A

5

DTE Energy - Detroit
Edison Company

Mohamad
Elhusseini

Abstain

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Selene Willis

Affirmative

N/A

5

Entergy - Entergy
Services, Inc.

Gail Golden

None

N/A

5

Evergy

Jeremy Harris

Affirmative

N/A

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Matthew
Corporation
Augustin
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Ryan Strom

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Florida Municipal Power
Agency

Chris Gowder

LaKenya
Vannorman

None

N/A

5

Great River Energy

Jacalynn Bentz

Joseph Knight

None

N/A

5

Greybeard Compliance
Services, LLC

Mike Gabriel

Abstain

N/A

5

Grid Strategies LLC

Michael Goggin

None

N/A

5

Hydro-Quebec (HQ)

Junji Yamaguchi

Chantal Mazza

Affirmative

N/A

5

Imperial Irrigation District

Tino Zaragoza

Denise Sanchez

Affirmative

N/A

5

Invenergy LLC

Rhonda Jones

None

N/A

5

JEA

John Babik

Affirmative

N/A

5

Lincoln Electric System

Brittany Millard

Abstain

N/A

5

Los Angeles Department
of Water and Power

Robert Kerrigan

Abstain

N/A

5

Lower Colorado River
Authority

Teresa Krabe

Abstain

N/A

5

LS Power Development,
LLC

C. A. Campbell

None

N/A

5

Manitoba Hydro

Kristy-Lee Young

None

N/A

5

Muscatine Power and
Water

Chance Back

Abstain

N/A

5

National Grid USA

Robin Berry

Affirmative

N/A

5

NB Power Corporation New Brunswick Power
Transmission Corporation

Erin Wilson

Abstain

N/A

5

Nebraska Public Power
District

Ronald Bender

Negative

Third-Party
Comments

5

New York Power Authority

Zahid Qayyum

Affirmative

N/A

5

NextEra Energy

Richard Vendetti

Negative

Comments
Submitted

Negative

Comments
Submitted

5

NiSource - Northern
Kathryn Tackett
Indiana Public Service Co.
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Helen Zhao

Kevin
Schawang

Segment

Organization

Voter

5

North Carolina Electric
Membership Corporation

Reid Cashion

5

OGE Energy - Oklahoma
Gas and Electric Co.

5

Designated
Proxy

NERC
Memo

Negative

Third-Party
Comments

Patrick Wells

Negative

Third-Party
Comments

Oglethorpe Power
Corporation

Donna Johnson

Negative

Third-Party
Comments

5

Omaha Public Power
District

Kayleigh
Wilkerson

Negative

Third-Party
Comments

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Affirmative

N/A

5

Orlando Utilities
Commission

Dania Colon

Affirmative

N/A

5

OTP - Otter Tail Power
Company

Stacy Wahlund

Negative

Third-Party
Comments

5

Pacific Gas and Electric
Company

Tyler Brun

Negative

Comments
Submitted

5

Pattern Operators LP

George E Brown

Negative

Third-Party
Comments

5

Platte River Power
Authority

Jon Osell

Affirmative

N/A

5

Portland General Electric
Co.

Ryan Olson

None

N/A

5

PSEG Nuclear LLC

Tim Kucey

None

N/A

5

Public Utility District No. 1
of Chelan County

Rebecca Zahler

Negative

Comments
Submitted

5

Public Utility District No. 1
of Snohomish County

Becky Burden

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Loren Harbachuk

None

N/A

5

Sacramento Municipal
Utility District

Ryder Couch

Tim Kelley

Affirmative

N/A

5

Salt River Project

Thomas Johnson

Israel Perez

Affirmative

N/A

Abstain

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
5
Santee Cooper
Carey Salisbury

Scott Brame

Ballot

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Seminole Electric
Cooperative, Inc.

Melanie Wong

None

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

Leslie Burke

Affirmative

N/A

5

Southern Indiana Gas and
Electric Co.

Larry Rogers

Abstain

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

Talen Generation, LLC

Donald Lock

Negative

Comments
Submitted

5

Tallahassee Electric (City
of Tallahassee, FL)

Karen Weaver

Abstain

N/A

5

Tennessee Valley
Authority

Darren Boehm

Negative

Comments
Submitted

5

Tri-State G and T
Association, Inc.

Sergio Banuelos

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Kalidass

Abstain

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Abstain

N/A

6

AEP

Mathew Miller

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Marcus Bortman

Affirmative

N/A

6

Associated Electric
Cooperative, Inc.

Brian Ackermann

Affirmative

N/A

6

Austin Energy

Imane Mrini

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Lindsay Wickizer

None

N/A

Affirmative

N/A

6
Black Hills Corporation
Rachel Schuldt
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Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Bonneville Power
Administration

Tanner Brier

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Negative

Third-Party
Comments

6

Con Ed - Consolidated
Edison Co. of New York

Jason Chandler

Affirmative

N/A

6

Constellation

Kimberly Turco

Abstain

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Affirmative

N/A

6

Duke Energy

John Sturgeon

Affirmative

N/A

6

Edison International Southern California
Edison Company

Stephanie Kenny

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Evergy

Tiffany Lake

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Corporation

Stacey Sheehan

Affirmative

N/A

6

Great River Energy

Brian Meloy

Negative

Third-Party
Comments

6

Imperial Irrigation District

Diana Torres

Affirmative

N/A

6

Lakeland Electric

Paul Shipps

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

Abstain

N/A

6

Manitoba Hydro

Brandin Stoesz

None

N/A

6

Muscatine Power and
Water

Nicholas Burns

Abstain

N/A

6

New York Power Authority

Shelly Dineen

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

Negative

Comments
Submitted

Negative

Comments
Submitted

6
NiSource - Northern
Rebecca Blair
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Indiana Public Service Co.

Hayden Maples

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

NRG - NRG Energy, Inc.

Martin Sidor

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Ashley F Stringer

Negative

Third-Party
Comments

6

Omaha Public Power
District

Shonda McCain

Negative

Third-Party
Comments

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Stefanie Burke

None

N/A

6

Powerex Corporation

Raj Hundal

Negative

Third-Party
Comments

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade LLC

Laura Wu

None

N/A

6

Public Utility District No. 1
of Chelan County

Tamarra Hardie

Negative

Comments
Submitted

6

Sacramento Municipal
Utility District

Charles Norton

Tim Kelley

Affirmative

N/A

6

Salt River Project

Timothy Singh

Israel Perez

Affirmative

N/A

6

Santee Cooper

Marty Watson

Abstain

N/A

6

Seminole Electric
Cooperative, Inc.

Bret Galbraith

None

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation and Energy
Marketing

Matthew O'neal

Affirmative

N/A

6

Southern Indiana Gas and
Electric Co.

Kati Barr

Abstain

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Segment

Organization

Voter

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

6

Western Area Power
Administration

6

Designated
Proxy
Jennie Wike

Ballot

NERC
Memo

Affirmative

N/A

Jennifer Neville

Affirmative

N/A

Xcel Energy, Inc.

Steve Szablya

None

N/A

8

Florida Reliability
Coordinating Council –
Member Services Division

Vince Ordax

Abstain

N/A

10

Midwest Reliability
Organization

Mark Flanary

Affirmative

N/A

10

New York State Reliability
Council

Wesley Yeomans

Affirmative

N/A

10

Northeast Power
Coordinating Council

Gerry Dunbar

Affirmative

N/A

10

ReliabilityFirst

Tremayne Brown

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

10

Western Electricity
Coordinating Council

Steven Rueckert

Affirmative

N/A

Greg Sorenson

Previous
Showing 1 to 314 of 314 entries

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BALLOT RESULTS  
Comment: View Comment Results (/CommentResults/Index/355)
Ballot Name: 2023-07 Transmission Planning Performance Requirements for Extreme Weather Implementation Plan AB 4
OT
Voting Start Date: 11/12/2024 12:01:00 AM
Voting End Date: 11/21/2024 8:00:00 PM
Ballot Type: OT
Ballot Activity: AB
Ballot Series: 4
Total # Votes: 261
Total Ballot Pool: 314
Quorum: 83.12
Quorum Established Date: 11/21/2024 3:56:12 PM
Weighted Segment Value: 77.72

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

89

1

48

0.762

15

0.238

0

16

10

Segment:
2

8

0.8

7

0.7

1

0.1

0

0

0

Segment:
3

68

1

39

0.78

11

0.22

0

7

11

Segment:
4

18

1

7

0.636

4

0.364

0

2

5

Segment:
5

76

1

30

0.714

12

0.286

0

14

20

Segment:
6

47

1

25

0.781

7

0.219

0

8

7

Segment:
7

0

0

0

0

0

0

0

0

0

0

0

0

1

0

Segment

Segment: 1
0
0
0
8
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Negative
Votes w/o
Comment

Abstain

No
Vote

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:
9

0

0

0

0

0

0

0

0

0

Segment:
10

7

0.6

6

0.6

0

0

0

1

0

Totals:

314

6.4

162

4.974

50

1.426

0

49

53

Segment

BALLOT POOL MEMBERS
Show

All

Segment

entries

Organization

Search:

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power,
Inc.

Hillary Creurer

Affirmative

N/A

1

Ameren - Ameren
Services

Tamara Evey

None

N/A

1

American Transmission
Company, LLC

Amy Wilke

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Daniela
Atanasovski

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Jennifer Bray

Affirmative

N/A

1

Associated Electric
Cooperative, Inc.

Mark Riley

Affirmative

N/A

1

Austin Energy

Thomas
Standifur

Affirmative

N/A

Affirmative

N/A

1
Avista - Avista
Mike Magruder
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Corporation

Segment

Organization

Voter

1

Balancing Authority of
Northern California

Kevin Smith

1

BC Hydro and Power
Authority

1

Designated
Proxy

NERC
Memo

Affirmative

N/A

Adrian Andreoiu

Negative

Comments
Submitted

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

Affirmative

N/A

1

Black Hills Corporation

Travis
Grablander

Affirmative

N/A

1

Bonneville Power
Administration

Kamala RogersHolliday

Affirmative

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Negative

Comments
Submitted

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

None

N/A

1

Central Iowa Power
Cooperative

Kevin Lyons

Negative

Third-Party
Comments

1

City Utilities of Springfield,
Missouri

Michael Bowman

Negative

Third-Party
Comments

1

Colorado Springs Utilities

Corey Walker

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dairyland Power
Cooperative

Karrie Schuldt

Negative

Third-Party
Comments

1

Dominion - Dominion
Virginia Power

Steven Belle

Affirmative

N/A

1

Duke Energy

Katherine Street

Affirmative

N/A

1

Edison International Southern California
Edison Company

Robert Blackney

Affirmative

N/A

1

Entergy

Brian Lindsey

None

N/A

1

Evergy

Kevin Frick

Affirmative

N/A

Affirmative

N/A

1 - NERC Ver 4.2.1.0
Eversource
Energy
Joshua London
© 2024
Machine
Name: ATLVPEROWEB01

Tim Kelley

Ballot

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

John Martinez

Affirmative

N/A

1

Georgia Transmission
Corporation

Greg Davis

Affirmative

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Negative

Third-Party
Comments

1

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Emma Halilovic

Lidija Efremova

Affirmative

N/A

1

Hydro-Quebec (HQ)

Nicolas Turcotte

Chantal Mazza

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Sean Steffensen

None

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Denise Sanchez

Affirmative

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Allie Gavin

Affirmative

N/A

1

JEA

Joseph McClung

Affirmative

N/A

1

KAMO Electric
Cooperative

Micah Breedlove

Affirmative

N/A

1

Lakeland Electric

Larry Watt

None

N/A

1

Lincoln Electric System

Josh Johnson

Abstain

N/A

1

Long Island Power
Authority

Isidoro Behar

Abstain

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Abstain

N/A

1

Lower Colorado River
Authority

Matt Lewis

Abstain

N/A

1

LS Power Transmission,
LLC

Jennifer
Richardson

Abstain

N/A

Affirmative

N/A

1

M and A Electric Power
William Price
Cooperative
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Stephen
Stafford

Segment

Organization

Voter

1

Manitoba Hydro

Nazra Gladu

1

MEAG Power

David Weekley

1

Minnkota Power
Cooperative Inc.

Theresa Allard

1

Muscatine Power and
Water

1

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Rebika Yitna

Abstain

N/A

Nikki CarsonMarquis

Negative

Third-Party
Comments

Andrew Kurriger

Abstain

N/A

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Jeffrey Streifling

Abstain

N/A

1

Nebraska Public Power
District

Jamison Cawley

Negative

Third-Party
Comments

1

New York Power Authority

Daniel Valle

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Negative

Comments
Submitted

1

NiSource - Northern
Indiana Public Service Co.

Alison Nickells

Negative

Comments
Submitted

1

Northeast Missouri
Electric Power
Cooperative

Brett Douglas

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Negative

Third-Party
Comments

1

Omaha Public Power
District

Doug Peterchuck

None

N/A

1

Oncor Electric Delivery

Byron Booker

Affirmative

N/A

1

Orlando Utilities
Commission

Aaron Staley

None

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Negative

Third-Party
Comments

1

Pacific Gas and Electric
Company

Marco Rios

Negative

Comments
Submitted

Affirmative

N/A

1
Platte River Power
Marissa Archie
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Authority

Broc Bruton

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Affirmative

N/A

1

Portland General Electric
Co.

Brooke Jockin

Abstain

N/A

1

PPL Electric Utilities
Corporation

Michelle
McCartney
Longo

Affirmative

N/A

1

PSEG - Public Service
Electric and Gas Co.

Karen Arnold

Affirmative

N/A

1

Public Utility District No. 1
of Chelan County

Diane E Landry

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Alyssia Rhoads

Affirmative

N/A

1

Public Utility District No. 2
of Grant County,
Washington

Joanne Anderson

Abstain

N/A

1

Sacramento Municipal
Utility District

Wei Shao

Tim Kelley

Affirmative

N/A

1

Salt River Project

Laura Somak

Israel Perez

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Abstain

N/A

1

SaskPower

Wayne
Guttormson

Abstain

N/A

1

Seminole Electric
Cooperative, Inc.

Kristine Ward

None

N/A

1

Sempra - San Diego Gas
and Electric

Mohamed
Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Abstain

N/A

Affirmative

N/A

1

Tacoma Public Utilities
John Merrell
(Tacoma, WA)
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Abstain

N/A

1

Tennessee Valley
Authority

David Plumb

Negative

Comments
Submitted

1

Tri-State G and T
Association, Inc.

Donna Wood

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Abstain

N/A

1

Unisource - Tucson
Electric Power Co.

Jessica Cordero

Negative

Comments
Submitted

1

VELCO -Vermont Electric
Power Company, Inc.

Randall Buswell

Abstain

N/A

1

Western Area Power
Administration

Ben Hammer

Affirmative

N/A

1

Xcel Energy, Inc.

Eric Barry

None

N/A

2

California ISO

Darcy O'Connell

Affirmative

N/A

2

Electric Reliability Council
of Texas, Inc.

Kennedy Meier

Affirmative

N/A

2

Independent Electricity
System Operator

Helen Lainis

Affirmative

N/A

2

ISO New England, Inc.

John Pearson

Affirmative

N/A

2

Midcontinent ISO, Inc.

Kirsten Rowley

Affirmative

N/A

2

New York Independent
System Operator

Gregory Campoli

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Thomas Foster

Elizabeth Davis

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Joshua Phillips

Shannon
Mickens

Negative

Comments
Submitted

3

AEP

Leshel Hutchings

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras Sr

Affirmative

N/A

Affirmative

N/A

3
APS - Arizona Public
Jessica Lopez
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Service Co.

Keith Jonassen

Danielle Moskop

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Arkansas Electric
Cooperative Corporation

Ayslynn Mcavoy

None

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

Lovita Griffin

Affirmative

N/A

3

Avista - Avista
Corporation

Robert Follini

Affirmative

N/A

3

BC Hydro and Power
Authority

Ming Jiang

Negative

Comments
Submitted

3

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Joseph Amato

Affirmative

N/A

3

Black Hills Corporation

Josh Combs

Affirmative

N/A

3

Bonneville Power
Administration

Ron Sporseen

Affirmative

N/A

3

Buckeye Power, Inc.

Tom Schmidt

None

N/A

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Affirmative

N/A

3

City Utilities of Springfield,
Missouri

Jessica
Morrissey

Negative

Third-Party
Comments

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

None

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Lincoln Burton

Affirmative

N/A

3

Dominion - Dominion
Virginia Power

Victoria Crider

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Marvin Johnson

Abstain

N/A

3

Duke Energy - Florida
Power Corporation

Marcelo
Pesantez

Affirmative

N/A

Affirmative

N/A

3

Edison International Romel Aquino
Southern California
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Edison Company

Carly Miller

Ryan Strom

Segment

Organization

Voter

3

Entergy

James Keele

3

Evergy

Marcus Moor

3

Eversource Energy

3

Designated
Proxy

Ballot

NERC
Memo

None

N/A

Affirmative

N/A

Vicki O'Leary

Affirmative

N/A

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

None

N/A

3

Great River Energy

Michael
Brytowski

Negative

Third-Party
Comments

3

Imperial Irrigation District

George Kirschner

Affirmative

N/A

3

JEA

Marilyn Williams

Affirmative

N/A

3

Lakeland Electric

Steven Marshall

None

N/A

3

Lincoln Electric System

Sam Christensen

Abstain

N/A

3

Los Angeles Department
of Water and Power

Fausto Serratos

None

N/A

3

M and A Electric Power
Cooperative

Gary Dollins

Affirmative

N/A

3

Manitoba Hydro

Mike Smith

Affirmative

N/A

3

MEAG Power

Roger Brand

Abstain

N/A

3

MGE Energy - Madison
Gas and Electric Co.

Benjamin Widder

Negative

Third-Party
Comments

3

Muscatine Power and
Water

Seth Shoemaker

Abstain

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Negative

Third-Party
Comments

3

New York Power Authority

Richard Machado

Affirmative

N/A

Negative

Comments
Submitted

3

NextEra Energy - Florida
Karen Demos
Power and Light Co.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Denise Sanchez

Rebika Yitna

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

NiSource - Northern
Indiana Public Service Co.

Steven
Taddeucci

Negative

Comments
Submitted

3

Northern California Power
Agency

Michael Whitney

None

N/A

3

NW Electric Power
Cooperative, Inc.

Heath Henry

Affirmative

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Negative

Third-Party
Comments

3

Omaha Public Power
District

David Heins

Negative

Third-Party
Comments

3

OTP - Otter Tail Power
Company

Wendi Olson

None

N/A

3

Pacific Gas and Electric
Company

Sandra Ellis

Negative

Comments
Submitted

3

Platte River Power
Authority

Richard Kiess

Affirmative

N/A

3

PNM Resources - Public
Service Company of New
Mexico

Amy
Wesselkamper

Affirmative

N/A

3

Portland General Electric
Co.

Mayra Franco

Abstain

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

Christopher
Murphy

Affirmative

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Tim Kelley

Affirmative

N/A

3

Salt River Project

Mathew Weber

Israel Perez

Affirmative

N/A

3

Santee Cooper

Vicky Budreau

Abstain

N/A

3

Seminole Electric
Cooperative, Inc.

Usama Tahir

None

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Sempra - San Diego Gas
and Electric

Bryan Bennett

Affirmative

N/A

3

Sho-Me Power Electric
Cooperative

Jarrod Murdaugh

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

Southern Indiana Gas and
Electric Co.

Ryan Snyder

Abstain

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

John Nierenberg

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Negative

Comments
Submitted

3

Tri-State G and T
Association, Inc.

Ryan Walter

Affirmative

N/A

3

Xcel Energy, Inc.

Nicholas Friebel

None

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Negative

Third-Party
Comments

4

Arkansas Electric
Cooperative Corporation

Jenni Sudduth

None

N/A

4

Austin Energy

Tony Hua

Affirmative

N/A

4

Buckeye Power, Inc.

Jason Procuniar

None

N/A

4

City Utilities of Springfield,
Missouri

Jerry Bradshaw

Negative

Third-Party
Comments

4

CMS Energy - Consumers
Energy Company

Aric Root

None

N/A

4

DTE Energy

Patricia Ireland

Abstain

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

Affirmative

N/A

4

Georgia System
Operations Corporation

Katrina Lyons

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Joseph Gatten

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

North Carolina Electric
Membership Corporation

Richard McCall

Scott Brame

Negative

Third-Party
Comments

4

Northern California Power
Agency

Marty Hostler

Mason Jones

None

N/A

4

Public Utility District No. 1
of Snohomish County

John D.
Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Abstain

N/A

4

Sacramento Municipal
Utility District

Foung Mua

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

George Pino

None

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

Utility Services, Inc.

Carver Powers

Affirmative

N/A

4

Western Power Pool

Kevin Conway

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

AES - AES Corporation

Ruchi Shah

None

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

None

N/A

5

APS - Arizona Public
Service Co.

Andrew Smith

Affirmative

N/A

5

Associated Electric
Cooperative, Inc.

Chuck Booth

None

N/A

5

Austin Energy

Michael Dillard

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

None

N/A

5

BC Hydro and Power
Authority

Christine
Jennings

None

N/A

5

Berkshire Hathaway - NV
Energy

Dwanique Spiller

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
5
Black Hills Corporation
Sheila Suurmeier

Affirmative

N/A

Tim Kelley

Jennie Wike

Segment

Organization

Voter

5

Bonneville Power
Administration

Milli Chennell

5

Buckeye Power, Inc.

Kevin Zemanek

5

California Department of
Water Resources

5

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

None

N/A

ASM Mostafa

None

N/A

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

None

N/A

5

Colorado Springs Utilities

Jeffrey Icke

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

Michelle Pagano

Affirmative

N/A

5

Constellation

Alison MacKellar

Abstain

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

Dairyland Power
Cooperative

Tommy Drea

Negative

Third-Party
Comments

5

Dominion - Dominion
Resources, Inc.

Barbara Marion

Affirmative

N/A

5

DTE Energy - Detroit
Edison Company

Mohamad
Elhusseini

Abstain

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Selene Willis

Affirmative

N/A

5

Entergy - Entergy
Services, Inc.

Gail Golden

None

N/A

5

Evergy

Jeremy Harris

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Corporation

Matthew
Augustin

Affirmative

N/A

5

Florida Municipal Power
Agency

Chris Gowder

LaKenya
Vannorman

None

N/A

Joseph Knight

None

N/A

5
Great River Energy
Jacalynn Bentz
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Ryan Strom

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Greybeard Compliance
Services, LLC

Mike Gabriel

Abstain

N/A

5

Grid Strategies LLC

Michael Goggin

None

N/A

5

Hydro-Quebec (HQ)

Junji Yamaguchi

Chantal Mazza

Affirmative

N/A

5

Imperial Irrigation District

Tino Zaragoza

Denise Sanchez

Affirmative

N/A

5

Invenergy LLC

Rhonda Jones

None

N/A

5

JEA

John Babik

Affirmative

N/A

5

Lincoln Electric System

Brittany Millard

Abstain

N/A

5

Los Angeles Department
of Water and Power

Robert Kerrigan

Abstain

N/A

5

Lower Colorado River
Authority

Teresa Krabe

Abstain

N/A

5

LS Power Development,
LLC

C. A. Campbell

None

N/A

5

Manitoba Hydro

Kristy-Lee Young

None

N/A

5

Muscatine Power and
Water

Chance Back

Abstain

N/A

5

National Grid USA

Robin Berry

Affirmative

N/A

5

NB Power Corporation New Brunswick Power
Transmission Corporation

Erin Wilson

Abstain

N/A

5

Nebraska Public Power
District

Ronald Bender

Negative

Third-Party
Comments

5

New York Power Authority

Zahid Qayyum

Affirmative

N/A

5

NextEra Energy

Richard Vendetti

Negative

Comments
Submitted

5

NiSource - Northern
Indiana Public Service Co.

Kathryn Tackett

Negative

Comments
Submitted

5

North Carolina Electric
Membership Corporation

Reid Cashion

Negative

Third-Party
Comments

Negative

Third-Party
Comments

5
OGE Energy - Oklahoma
Patrick Wells
© 2024 - NERC Ver 4.2.1.0
Machine
Name:
ATLVPEROWEB01
Gas and Electric Co.

Helen Zhao

Kevin
Schawang

Scott Brame

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Oglethorpe Power
Corporation

Donna Johnson

Negative

Third-Party
Comments

5

Omaha Public Power
District

Kayleigh
Wilkerson

Negative

Third-Party
Comments

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Affirmative

N/A

5

Orlando Utilities
Commission

Dania Colon

Affirmative

N/A

5

OTP - Otter Tail Power
Company

Stacy Wahlund

Negative

Third-Party
Comments

5

Pacific Gas and Electric
Company

Tyler Brun

Negative

Comments
Submitted

5

Pattern Operators LP

George E Brown

Negative

Third-Party
Comments

5

Platte River Power
Authority

Jon Osell

Affirmative

N/A

5

Portland General Electric
Co.

Ryan Olson

None

N/A

5

PSEG Nuclear LLC

Tim Kucey

None

N/A

5

Public Utility District No. 1
of Chelan County

Rebecca Zahler

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Becky Burden

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Loren Harbachuk

None

N/A

5

Sacramento Municipal
Utility District

Ryder Couch

Tim Kelley

Affirmative

N/A

5

Salt River Project

Thomas Johnson

Israel Perez

Affirmative

N/A

5

Santee Cooper

Carey Salisbury

Abstain

N/A

5

Seminole Electric
Cooperative, Inc.

Melanie Wong

None

N/A

Affirmative

N/A

5
Sempra - San Diego Gas
Jennifer Wright
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
and Electric

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Southern Company Southern Company
Generation

Leslie Burke

Affirmative

N/A

5

Southern Indiana Gas and
Electric Co.

Larry Rogers

Abstain

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

Talen Generation, LLC

Donald Lock

Affirmative

N/A

5

Tallahassee Electric (City
of Tallahassee, FL)

Karen Weaver

Abstain

N/A

5

Tennessee Valley
Authority

Darren Boehm

Negative

Comments
Submitted

5

Tri-State G and T
Association, Inc.

Sergio Banuelos

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Kalidass

Abstain

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Abstain

N/A

6

AEP

Mathew Miller

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Marcus Bortman

Affirmative

N/A

6

Associated Electric
Cooperative, Inc.

Brian Ackermann

Affirmative

N/A

6

Austin Energy

Imane Mrini

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Lindsay Wickizer

None

N/A

6

Black Hills Corporation

Rachel Schuldt

Affirmative

N/A

6

Bonneville Power
Administration

Tanner Brier

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Negative

Third-Party
Comments

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Con Ed - Consolidated
Edison Co. of New York

Jason Chandler

Affirmative

N/A

6

Constellation

Kimberly Turco

Abstain

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Affirmative

N/A

6

Duke Energy

John Sturgeon

Affirmative

N/A

6

Edison International Southern California
Edison Company

Stephanie Kenny

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Evergy

Tiffany Lake

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Corporation

Stacey Sheehan

Affirmative

N/A

6

Great River Energy

Brian Meloy

Negative

Third-Party
Comments

6

Imperial Irrigation District

Diana Torres

Affirmative

N/A

6

Lakeland Electric

Paul Shipps

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

Abstain

N/A

6

Manitoba Hydro

Brandin Stoesz

None

N/A

6

Muscatine Power and
Water

Nicholas Burns

Abstain

N/A

6

New York Power Authority

Shelly Dineen

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

Negative

Comments
Submitted

6

NiSource - Northern
Indiana Public Service Co.

Rebecca Blair

Negative

Comments
Submitted

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

Abstain

N/A

6
NRG - NRG Energy, Inc.
Martin Sidor
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

OGE Energy - Oklahoma
Gas and Electric Co.

Ashley F Stringer

Negative

Third-Party
Comments

6

Omaha Public Power
District

Shonda McCain

Negative

Third-Party
Comments

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Stefanie Burke

None

N/A

6

Powerex Corporation

Raj Hundal

Negative

Third-Party
Comments

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade LLC

Laura Wu

None

N/A

6

Public Utility District No. 1
of Chelan County

Tamarra Hardie

Affirmative

N/A

6

Sacramento Municipal
Utility District

Charles Norton

Tim Kelley

Affirmative

N/A

6

Salt River Project

Timothy Singh

Israel Perez

Affirmative

N/A

6

Santee Cooper

Marty Watson

Abstain

N/A

6

Seminole Electric
Cooperative, Inc.

Bret Galbraith

None

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation and Energy
Marketing

Matthew O'neal

Affirmative

N/A

6

Southern Indiana Gas and
Electric Co.

Kati Barr

Abstain

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

Affirmative

N/A

Affirmative

N/A

6

Western Area Power
Jennifer Neville
Administration
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Xcel Energy, Inc.

Steve Szablya

None

N/A

8

Florida Reliability
Coordinating Council –
Member Services Division

Vince Ordax

Abstain

N/A

10

Midwest Reliability
Organization

Mark Flanary

Affirmative

N/A

10

New York State Reliability
Council

Wesley Yeomans

Affirmative

N/A

10

Northeast Power
Coordinating Council

Gerry Dunbar

Affirmative

N/A

10

ReliabilityFirst

Tremayne Brown

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

10

Western Electricity
Coordinating Council

Steven Rueckert

Abstain

N/A

Greg Sorenson

Previous
Showing 1 to 314 of 314 entries

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BALLOT RESULTS  
Ballot Name: 2023-07 Transmission Planning Performance Requirements for Extreme Weather TPL-008-1 | Non-binding Poll
AB 4 NB
Voting Start Date: 11/12/2024 12:01:00 AM
Voting End Date: 11/21/2024 8:00:00 PM
Ballot Type: NB
Ballot Activity: AB
Ballot Series: 4
Total # Votes: 250
Total Ballot Pool: 297
Quorum: 84.18
Quorum Established Date: 11/21/2024 3:28:13 PM
Weighted Segment Value: 73.4
Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
1

86

1

40

0.714

16

0.286

20

10

Segment:
2

7

0.5

3

0.3

2

0.2

2

0

Segment:
3

63

1

33

0.767

10

0.233

12

8

Segment:
4

18

1

7

0.636

4

0.364

2

5

Segment:
5

72

1

28

0.718

11

0.282

15

18

Segment:
6

44

1

22

0.759

7

0.241

9

6

Segment:
7

0

0

0

0

0

0

0

0

Segment:
8

1

0

0

0

0

0

1

0

Segment:
9

0

0

0

0

0

0

0

0

Segment

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
10

6

0.5

5

0.5

0

0

1

0

Totals:

297

6

138

4.395

50

1.605

62

47

Segment

BALLOT POOL MEMBERS
Show

All

Segment

entries

Organization

Search:

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power,
Inc.

Hillary Creurer

Affirmative

N/A

1

Ameren - Ameren
Services

Tamara Evey

None

N/A

1

American Transmission
Company, LLC

Amy Wilke

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Daniela
Atanasovski

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Jennifer Bray

Affirmative

N/A

1

Associated Electric
Cooperative, Inc.

Mark Riley

Affirmative

N/A

1

Austin Energy

Thomas
Standifur

Affirmative

N/A

1

Avista - Avista Corporation

Mike Magruder

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

Negative

Comments
Submitted

1
BC Hydro and Power
Adrian Andreoiu
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Authority

Tim Kelley

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

Affirmative

N/A

1

Black Hills Corporation

Travis
Grablander

Affirmative

N/A

1

Bonneville Power
Administration

Kamala RogersHolliday

Affirmative

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Negative

Comments
Submitted

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

None

N/A

1

Central Iowa Power
Cooperative

Kevin Lyons

Negative

Comments
Submitted

1

City Utilities of Springfield,
Missouri

Michael Bowman

Negative

Comments
Submitted

1

Colorado Springs Utilities

Corey Walker

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dairyland Power
Cooperative

Karrie Schuldt

Negative

Comments
Submitted

1

Dominion - Dominion
Virginia Power

Steven Belle

Affirmative

N/A

1

Duke Energy

Katherine Street

Affirmative

N/A

1

Edison International Southern California
Edison Company

Robert Blackney

Affirmative

N/A

1

Entergy

Brian Lindsey

None

N/A

1

Evergy

Kevin Frick

Affirmative

N/A

1

Eversource Energy

Joshua London

Negative

Comments
Submitted

1

Exelon

Daniel Gacek

Affirmative

N/A

FirstEnergy - FirstEnergy
John Martinez
Corporation
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB01

Affirmative

N/A

1

Hayden Maples

Segment

Organization

Voter

1

Georgia Transmission
Corporation

Greg Davis

1

Glencoe Light and Power
Commission

1

Designated
Proxy

NERC
Memo

Negative

Comments
Submitted

Terry Volkmann

Negative

Comments
Submitted

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Emma Halilovic

Lidija Efremova

Abstain

N/A

1

Hydro-Quebec (HQ)

Nicolas Turcotte

Chantal Mazza

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Sean Steffensen

None

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Denise Sanchez

Affirmative

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Allie Gavin

Affirmative

N/A

1

JEA

Joseph McClung

Affirmative

N/A

1

KAMO Electric
Cooperative

Micah Breedlove

Affirmative

N/A

1

Lakeland Electric

Larry Watt

None

N/A

1

Lincoln Electric System

Josh Johnson

Abstain

N/A

1

Long Island Power
Authority

Isidoro Behar

Abstain

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Abstain

N/A

1

Lower Colorado River
Authority

Matt Lewis

Abstain

N/A

1

LS Power Transmission,
LLC

Jennifer
Richardson

Abstain

N/A

1

M and A Electric Power
Cooperative

William Price

Affirmative

N/A

1

MEAG Power

David Weekley

Rebika Yitna

Abstain

N/A

Nikki CarsonMarquis

Negative

Comments
Submitted

1

Minnkota Power
Theresa Allard
Cooperative Inc.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Stephen
Stafford

Ballot

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Muscatine Power and
Water

Andrew Kurriger

Abstain

N/A

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Jeffrey Streifling

Negative

Comments
Submitted

1

Nebraska Public Power
District

Jamison Cawley

Abstain

N/A

1

New York Power Authority

Daniel Valle

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Abstain

N/A

1

NiSource - Northern
Indiana Public Service Co.

Alison Nickells

Negative

Comments
Submitted

1

Northeast Missouri
Electric Power
Cooperative

Brett Douglas

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Negative

Comments
Submitted

1

Omaha Public Power
District

Doug Peterchuck

None

N/A

1

Oncor Electric Delivery

Byron Booker

Negative

Comments
Submitted

1

Orlando Utilities
Commission

Aaron Staley

None

N/A

1

Pacific Gas and Electric
Company

Marco Rios

Negative

Comments
Submitted

1

Platte River Power
Authority

Marissa Archie

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Affirmative

N/A

Abstain

N/A

1

Portland General Electric
Brooke Jockin
Co. Machine Name: ATLVPEROWEB01
© 2024 - NERC Ver 4.2.1.0

Broc Bruton

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

PPL Electric Utilities
Corporation

Michelle
McCartney
Longo

None

N/A

1

PSEG - Public Service
Electric and Gas Co.

Karen Arnold

Abstain

N/A

1

Public Utility District No. 1
of Chelan County

Diane E Landry

Negative

Comments
Submitted

1

Public Utility District No. 1
of Snohomish County

Alyssia Rhoads

Affirmative

N/A

1

Public Utility District No. 2
of Grant County,
Washington

Joanne Anderson

Abstain

N/A

1

Sacramento Municipal
Utility District

Wei Shao

Tim Kelley

Affirmative

N/A

1

Salt River Project

Laura Somak

Israel Perez

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Abstain

N/A

1

SaskPower

Wayne
Guttormson

Abstain

N/A

1

Seminole Electric
Cooperative, Inc.

Kristine Ward

None

N/A

1

Sempra - San Diego Gas
and Electric

Mohamed
Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Abstain

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

David Plumb

Abstain

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Tri-State G and T
Association, Inc.

Donna Wood

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Abstain

N/A

1

Unisource - Tucson
Electric Power Co.

Jessica Cordero

Negative

Comments
Submitted

1

VELCO -Vermont Electric
Power Company, Inc.

Randall Buswell

Abstain

N/A

1

Western Area Power
Administration

Ben Hammer

Affirmative

N/A

2

Electric Reliability Council
of Texas, Inc.

Kennedy Meier

Negative

Comments
Submitted

2

Independent Electricity
System Operator

Helen Lainis

Abstain

N/A

2

ISO New England, Inc.

John Pearson

Affirmative

N/A

2

Midcontinent ISO, Inc.

Kirsten Rowley

Affirmative

N/A

2

New York Independent
System Operator

Gregory Campoli

Abstain

N/A

2

PJM Interconnection,
L.L.C.

Thomas Foster

Elizabeth Davis

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Joshua Phillips

Shannon
Mickens

Negative

Comments
Submitted

3

AEP

Leshel Hutchings

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras Sr

Abstain

N/A

3

APS - Arizona Public
Service Co.

Jessica Lopez

Affirmative

N/A

3

Arkansas Electric
Cooperative Corporation

Ayslynn Mcavoy

None

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

Lovita Griffin

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
3
Avista - Avista Corporation
Robert Follini

Affirmative

N/A

Keith Jonassen

Danielle Moskop

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

BC Hydro and Power
Authority

Ming Jiang

Negative

Comments
Submitted

3

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Joseph Amato

Affirmative

N/A

3

Black Hills Corporation

Josh Combs

Affirmative

N/A

3

Bonneville Power
Administration

Ron Sporseen

Affirmative

N/A

3

Buckeye Power, Inc.

Tom Schmidt

None

N/A

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Affirmative

N/A

3

City Utilities of Springfield,
Missouri

Jessica
Morrissey

Negative

Comments
Submitted

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

None

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Lincoln Burton

Affirmative

N/A

3

Dominion - Dominion
Virginia Power

Victoria Crider

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Marvin Johnson

Abstain

N/A

3

Duke Energy - Florida
Power Corporation

Marcelo
Pesantez

Affirmative

N/A

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Entergy

James Keele

None

N/A

3

Evergy

Marcus Moor

Affirmative

N/A

3

Eversource Energy

Vicki O'Leary

Negative

Comments
Submitted

3

Exelon

Kinte Whitehead

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Carly Miller

Ryan Strom

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Affirmative

N/A

3

Great River Energy

Michael
Brytowski

Negative

Comments
Submitted

3

Imperial Irrigation District

George Kirschner

Affirmative

N/A

3

JEA

Marilyn Williams

Affirmative

N/A

3

Lakeland Electric

Steven Marshall

None

N/A

3

Lincoln Electric System

Sam Christensen

Abstain

N/A

3

M and A Electric Power
Cooperative

Gary Dollins

Affirmative

N/A

3

MEAG Power

Roger Brand

Abstain

N/A

3

MGE Energy - Madison
Gas and Electric Co.

Benjamin Widder

Negative

Comments
Submitted

3

Muscatine Power and
Water

Seth Shoemaker

Abstain

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

Richard Machado

Affirmative

N/A

3

NextEra Energy - Florida
Power and Light Co.

Karen Demos

Abstain

N/A

3

NiSource - Northern
Indiana Public Service Co.

Steven
Taddeucci

Negative

Comments
Submitted

3

Northern California Power
Agency

Michael Whitney

None

N/A

3

NW Electric Power
Cooperative, Inc.

Heath Henry

Affirmative

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Negative

Comments
Submitted

3

Omaha Public Power
District

David Heins

Negative

Comments
Submitted

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Denise Sanchez

Rebika Yitna

Segment

Organization

Voter

3

Pacific Gas and Electric
Company

Sandra Ellis

3

Platte River Power
Authority

3

Designated
Proxy

NERC
Memo

Negative

Comments
Submitted

Richard Kiess

Affirmative

N/A

PNM Resources - Public
Service Company of New
Mexico

Amy
Wesselkamper

Affirmative

N/A

3

Portland General Electric
Co.

Mayra Franco

Abstain

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

Christopher
Murphy

Abstain

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Negative

Comments
Submitted

3

Sacramento Municipal
Utility District

Nicole Looney

Tim Kelley

Affirmative

N/A

3

Salt River Project

Mathew Weber

Israel Perez

Affirmative

N/A

3

Santee Cooper

Vicky Budreau

Abstain

N/A

3

Seminole Electric
Cooperative, Inc.

Usama Tahir

None

N/A

3

Sempra - San Diego Gas
and Electric

Bryan Bennett

Affirmative

N/A

3

Sho-Me Power Electric
Cooperative

Jarrod Murdaugh

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

Southern Indiana Gas and
Electric Co.

Ryan Snyder

Abstain

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

John Nierenberg

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Bob Cardle

Ballot

Jennie Wike

Segment

Designated
Proxy

Voter

3

Tennessee Valley
Authority

Ian Grant

Abstain

N/A

3

Tri-State G and T
Association, Inc.

Ryan Walter

Affirmative

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Negative

Comments
Submitted

4

Arkansas Electric
Cooperative Corporation

Jenni Sudduth

None

N/A

4

Austin Energy

Tony Hua

Affirmative

N/A

4

Buckeye Power, Inc.

Jason Procuniar

None

N/A

4

City Utilities of Springfield,
Missouri

Jerry Bradshaw

Negative

Comments
Submitted

4

CMS Energy - Consumers
Energy Company

Aric Root

None

N/A

4

DTE Energy

Patricia Ireland

Abstain

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

Affirmative

N/A

4

Georgia System
Operations Corporation

Katrina Lyons

Negative

Comments
Submitted

4

North Carolina Electric
Membership Corporation

Richard McCall

Scott Brame

Negative

Comments
Submitted

4

Northern California Power
Agency

Marty Hostler

Mason Jones

None

N/A

4

Public Utility District No. 1
of Snohomish County

John D.
Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Abstain

N/A

4

Sacramento Municipal
Utility District

Foung Mua

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

George Pino

None

N/A

Affirmative

N/A

4 - NERC Ver 4.2.1.0
Tacoma
Public Utilities
Hien Ho
© 2024
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Name: ATLVPEROWEB01
(Tacoma, WA)

Ryan Strom

Tim Kelley

Jennie Wike

Ballot

NERC
Memo

Organization

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

Utility Services, Inc.

Carver Powers

Affirmative

N/A

4

Western Power Pool

Kevin Conway

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

AES - AES Corporation

Ruchi Shah

None

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

None

N/A

5

APS - Arizona Public
Service Co.

Andrew Smith

Affirmative

N/A

5

Associated Electric
Cooperative, Inc.

Chuck Booth

None

N/A

5

Austin Energy

Michael Dillard

Affirmative

N/A

5

Avista - Avista Corporation

Glen Farmer

None

N/A

5

BC Hydro and Power
Authority

Christine
Jennings

None

N/A

5

Berkshire Hathaway - NV
Energy

Dwanique Spiller

Affirmative

N/A

5

Black Hills Corporation

Sheila Suurmeier

Affirmative

N/A

5

Bonneville Power
Administration

Milli Chennell

Affirmative

N/A

5

Buckeye Power, Inc.

Kevin Zemanek

None

N/A

5

California Department of
Water Resources

ASM Mostafa

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

None

N/A

5

Colorado Springs Utilities

Jeffrey Icke

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

Michelle Pagano

Affirmative

N/A

5

Constellation

Alison MacKellar

Abstain

N/A

© 2024
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CowlitzMachine
County Name:
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Deanna Carlson

Abstain

N/A

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Dairyland Power
Cooperative

Tommy Drea

Negative

Comments
Submitted

5

Dominion - Dominion
Resources, Inc.

Barbara Marion

Affirmative

N/A

5

DTE Energy - Detroit
Edison Company

Mohamad
Elhusseini

Abstain

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Selene Willis

Affirmative

N/A

5

Entergy - Entergy
Services, Inc.

Gail Golden

None

N/A

5

Evergy

Jeremy Harris

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Corporation

Matthew
Augustin

Affirmative

N/A

5

Florida Municipal Power
Agency

Chris Gowder

None

N/A

5

Greybeard Compliance
Services, LLC

Mike Gabriel

Abstain

N/A

5

Grid Strategies LLC

Michael Goggin

None

N/A

5

Hydro-Quebec (HQ)

Junji Yamaguchi

Chantal Mazza

Affirmative

N/A

5

Imperial Irrigation District

Tino Zaragoza

Denise Sanchez

Affirmative

N/A

5

JEA

John Babik

Affirmative

N/A

5

Lincoln Electric System

Brittany Millard

Abstain

N/A

5

Los Angeles Department
of Water and Power

Robert Kerrigan

Abstain

N/A

5

Lower Colorado River
Authority

Teresa Krabe

Abstain

N/A

5

LS Power Development,
LLC

C. A. Campbell

None

N/A

Abstain

N/A

5

Muscatine Power and
Chance Back
Water
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

LaKenya
Vannorman

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

National Grid USA

Robin Berry

Affirmative

N/A

5

NB Power Corporation New Brunswick Power
Transmission Corporation

Erin Wilson

Abstain

N/A

5

Nebraska Public Power
District

Ronald Bender

Abstain

N/A

5

New York Power Authority

Zahid Qayyum

Affirmative

N/A

5

NextEra Energy

Richard Vendetti

Negative

Comments
Submitted

5

NiSource - Northern
Indiana Public Service Co.

Kathryn Tackett

Negative

Comments
Submitted

5

North Carolina Electric
Membership Corporation

Reid Cashion

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Negative

Comments
Submitted

5

Oglethorpe Power
Corporation

Donna Johnson

Negative

Comments
Submitted

5

Omaha Public Power
District

Kayleigh
Wilkerson

Negative

Comments
Submitted

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Affirmative

N/A

5

Orlando Utilities
Commission

Dania Colon

Affirmative

N/A

5

OTP - Otter Tail Power
Company

Stacy Wahlund

Negative

Comments
Submitted

5

Pacific Gas and Electric
Company

Tyler Brun

Negative

Comments
Submitted

5

Pattern Operators LP

George E Brown

Negative

Comments
Submitted

5

Platte River Power
Authority

Jon Osell

Affirmative

N/A

5

Portland General Electric
Co.

Ryan Olson

None

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
5
PSEG Nuclear LLC
Tim Kucey

None

N/A

Kevin Schawang

Scott Brame

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Public Utility District No. 1
of Chelan County

Rebecca Zahler

Negative

Comments
Submitted

5

Public Utility District No. 1
of Snohomish County

Becky Burden

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Loren Harbachuk

None

N/A

5

Sacramento Municipal
Utility District

Ryder Couch

Tim Kelley

Affirmative

N/A

5

Salt River Project

Thomas Johnson

Israel Perez

Affirmative

N/A

5

Santee Cooper

Carey Salisbury

Abstain

N/A

5

Seminole Electric
Cooperative, Inc.

Melanie Wong

None

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

Leslie Burke

Affirmative

N/A

5

Southern Indiana Gas and
Electric Co.

Larry Rogers

Abstain

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

Tallahassee Electric (City
of Tallahassee, FL)

Karen Weaver

Abstain

N/A

5

Tennessee Valley
Authority

Darren Boehm

None

N/A

5

Tri-State G and T
Association, Inc.

Sergio Banuelos

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Kalidass

Abstain

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Abstain

N/A

6

AEP

Mathew Miller

Affirmative

N/A

Abstain

N/A

6
Ameren - Ameren
Robert Quinlivan
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Services

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

APS - Arizona Public
Service Co.

Marcus Bortman

Affirmative

N/A

6

Associated Electric
Cooperative, Inc.

Brian Ackermann

Affirmative

N/A

6

Austin Energy

Imane Mrini

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Lindsay Wickizer

None

N/A

6

Black Hills Corporation

Rachel Schuldt

Affirmative

N/A

6

Bonneville Power
Administration

Tanner Brier

Affirmative

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Jason Chandler

Affirmative

N/A

6

Constellation

Kimberly Turco

Abstain

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Affirmative

N/A

6

Duke Energy

John Sturgeon

Affirmative

N/A

6

Edison International Southern California
Edison Company

Stephanie Kenny

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Evergy

Tiffany Lake

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Corporation

Stacey Sheehan

Affirmative

N/A

6

Great River Energy

Brian Meloy

Negative

Comments
Submitted

6

Imperial Irrigation District

Diana Torres

Affirmative

N/A

6

Lakeland Electric

Paul Shipps

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

Abstain

N/A

Abstain

N/A

6
Muscatine Power and
Nicholas Burns
© 2024 - NERC Ver 4.2.1.0
Machine
Name:
ATLVPEROWEB01
Water

Hayden Maples

Denise Sanchez

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

New York Power Authority

Shelly Dineen

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

Negative

Comments
Submitted

6

NiSource - Northern
Indiana Public Service Co.

Rebecca Blair

Negative

Comments
Submitted

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

NRG - NRG Energy, Inc.

Martin Sidor

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Ashley F Stringer

Negative

Comments
Submitted

6

Omaha Public Power
District

Shonda McCain

Negative

Comments
Submitted

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Stefanie Burke

None

N/A

6

Powerex Corporation

Raj Hundal

Negative

Comments
Submitted

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

PSEG - PSEG Energy
Resources and Trade LLC

Laura Wu

None

N/A

6

Public Utility District No. 1
of Chelan County

Tamarra Hardie

Negative

Comments
Submitted

6

Sacramento Municipal
Utility District

Charles Norton

Tim Kelley

Affirmative

N/A

6

Salt River Project

Timothy Singh

Israel Perez

Affirmative

N/A

6

Santee Cooper

Marty Watson

Abstain

N/A

6

Seminole Electric
Cooperative, Inc.

Bret Galbraith

None

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Southern Company Southern Company
Generation and Energy
Marketing

Matthew O'neal

Affirmative

N/A

6

Southern Indiana Gas and
Electric Co.

Kati Barr

Abstain

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

Affirmative

N/A

6

Western Area Power
Administration

Jennifer Neville

Affirmative

N/A

8

Florida Reliability
Coordinating Council –
Member Services Division

Vince Ordax

Abstain

N/A

10

Midwest Reliability
Organization

Mark Flanary

Affirmative

N/A

10

Northeast Power
Coordinating Council

Gerry Dunbar

Affirmative

N/A

10

ReliabilityFirst

Tremayne Brown

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

10

Western Electricity
Coordinating Council

Steven Rueckert

Abstain

N/A

Jennie Wike

Greg Sorenson

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

This is the final draft of the proposed standard.
Completed Actions

Date

Standards Committee approved Standard Authorization Request (SAR)
for posting

July 19, 2023

SAR posted for comment

August 8–September 27,
2023

45-day formal comment period with initial ballot

March 20–May 3, 2024

38-day formal comment period with additional ballot

July 16–August 22, 2024

15-day formal comment period with additional ballot

October 7–21, 2024

15-day formal comment period with additional ballot

November 7–21, 2024

Anticipated Actions

Date

5-day final ballot

December 2–6, 2024

Board adoption

December 10, 2024

Final Draft of TPL-008-1
December 2024

Page 1 of 24

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

New or Modified Term(s) Used in NERC Reliability Standards

This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):

Extreme Temperature Assessment – Documented evaluation of future Bulk Electric System
performance for extreme heat and extreme cold benchmark temperature events.

Final Draft of TPL-008-1
December 2024

Page 2 of 24

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements for Extreme
Temperature Events

2.

Number:

TPL-008-1

3.

Purpose:

Establish Transmission system planning performance requirements to
develop a Bulk Power System (BPS) that will operate reliably during
extreme heat and extreme cold temperature events.

4.

Applicability:
4.1. Functional Entities:
4.1.1. Transmission Planner
4.1.2. Planning Coordinator

5.

Effective Date: See Implementation Plan for Project 2023-07.

Final Draft of TPL-008-1
December 2024

Page 3 of 24

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

B. Requirements and Measures
R1. Each Planning Coordinator shall identify, in conjunction with its Transmission
Planner(s), each entity’s individual and joint responsibilities for completing the
Extreme Temperature Assessment, which shall include each of the responsibilities
described in Requirements R2 through R11. Each responsible entity shall complete its
responsibilities such that the Extreme Temperature Assessment is completed at least
once every five calendar years. [Violation Risk Factor: Lower] [Time Horizon: Long-term
Planning]
M1. Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
provide dated documentation of each entity’s individual and joint responsibilities,
such as meeting minutes, agreements, copies of procedures, or protocols in effect
between entities or between departments of a vertically integrated system, or email
correspondence that identifies an agreement has been reached on individual and joint
responsibilities for completing the Extreme Temperature Assessment, and that these
responsibilities were completed such that the Extreme Temperature Assessment was
completed once every five calendar years.
R2. Each Planning Coordinator shall identify the zone(s) to which the Planning Coordinator
belongs to under Attachment 1 and shall coordinate with all Planning Coordinators
within each of its identified zone(s), to identify one common extreme heat benchmark
temperature event and one common extreme cold benchmark temperature event for
each of its identified zone(s) when completing the Extreme Temperature Assessment.
The benchmark temperature events shall be obtained from the benchmark library
maintained by the ERO or developed by the Planning Coordinators. Each benchmark
temperature event identified by the Planning Coordinators shall: [Violation Risk
Factor: High] [Time Horizon: Long-term Planning]
2.1. Consider no less than a 40-year period of temperature data ending no more than
five years prior to the time the benchmark temperature events are selected; and
2.2. Represent one of the 20 most extreme temperature conditions based on the
three-day rolling average of daily maximum (heat) or daily minimum (cold)
temperature across the zone.
M2. Each Planning Coordinator shall have evidence in either electronic or hard copy format
that it identified the zone(s) to which it belongs to, under Attachment 1, and that it
coordinated with all other Planning Coordinators within each of its identified zone(s)
to identify one common extreme heat benchmark temperature event and one
common extreme cold benchmark temperature event meeting the criteria of
Requirement R2 for each of their identified zone(s) when completing the Extreme
Temperature Assessment.
R3. Each Planning Coordinator shall coordinate with all Planning Coordinators within each
of its zone(s) identified in Requirement R2, to implement a process for developing
Final Draft of TPL-008-1
December 2024

Page 4 of 24

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

benchmark planning cases for the Extreme Temperature Assessment that represent
the benchmark temperature events selected in Requirement R2 and sensitivity cases
to demonstrate the impact of changes to the basic assumptions used in the
benchmark planning cases. This process shall include the following: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
3.1. Selection of System models within the Long-Term Transmission Planning Horizon
to form the basis for the benchmark planning cases.
3.2. Forecasted seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers within the zone.
3.3. Assumed seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers in areas outside the zone, as needed.
3.4. Identification of changes to at least one of the following conditions for sensitivity
cases: generation, real and reactive forecasted Load, or transfers.
M3. Each Planning Coordinator shall have dated evidence that it implemented a process
for coordinating the development of benchmark planning cases and sensitivity cases
for the Extreme Temperature Assessment as specified in Requirement R3.
R4. Each responsible entity, as identified in Requirement R1, shall use the process
developed in Requirement R3 and data consistent with that provided in accordance
with the MOD-032 standard, supplemented by other sources as needed, to develop
the following and establish category P0 as the normal System condition in Table 1:
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. One common extreme heat and one common extreme cold benchmark planning
case.
4.2. One common extreme heat and one common extreme cold sensitivity case.
M4. Each responsible entity, as identified in Requirement R1, shall have dated evidence in
either electronic or hard copy format that it developed benchmark planning cases and
sensitivity cases in accordance with Requirement R4.
R5. Each responsible entity, as identified in Requirement R1, shall have criteria for
acceptable System steady state voltage limits and post-Contingency voltage deviations
for completing the Extreme Temperature Assessment. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning]
M5. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of the documentation, specifying the criteria for
acceptable System steady state voltage limits and post-Contingency voltage deviations
for completing the Extreme Temperature Assessment.
R6. Each responsible entity, as identified in Requirement R1, shall define and document
the criteria or methodology to be used in the Extreme Temperature Assessment to
Final Draft of TPL-008-1
December 2024

Page 5 of 24

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

identify instability, uncontrolled separation, or Cascading within an Interconnection.
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
M6. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, specifying the criteria or
methodology to be used in the Extreme Temperature Assessment to identify
instability, uncontrolled separation, or Cascading within an Interconnection in
accordance with Requirement R6.
R7. Each responsible entity, as identified in Requirement R1, shall identify the
Contingencies for each category in Table 1 that are expected to produce more severe
System impacts on its portion of the Bulk Electric System. The rationale for those
Contingencies selected for evaluation shall be available as supporting information.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M7. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of the Contingencies for each
category in Table 1 that are expected to produce more severe System impacts on its
portion of the Bulk Electric System along with supporting rationale.
R8. Each responsible entity, as identified in Requirement R1, shall complete steady state
and transient stability analyses in the Extreme Temperature Assessment using the
Contingencies identified in Requirement R7, and shall document the assumptions and
results. Steady state and transient stability analyses shall be performed for the
following: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
8.1. Benchmark planning cases developed in accordance with Requirement R4 Part
4.1.
8.2. Sensitivity cases developed in accordance with Requirement R4 Part 4.2.
M8. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of the assumptions and results of
the steady state and transient stability analyses completed in the Extreme
Temperature Assessment.
R9. Each responsible entity, as identified in Requirement R1, shall develop a Corrective
Action Plan(s) when the analysis of a benchmark planning case, in accordance with
Requirement R8 Part 8.1, indicates its portion of the Bulk Electric System is unable to
meet performance requirements for category P0 or P1 in Table 1. For each Corrective
Action Plan, the responsible entity shall: [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
9.1. Document alternative(s) considered when Non-Consequential Load Loss is
utilized as an element of a Corrective Action Plan for a Table 1 P1 Contingency.
9.2. Be permitted to utilize Non-Consequential Load Loss as an interim solution,
which normally is not permitted for category P0 in Table 1 for situations that are
Final Draft of TPL-008-1
December 2024

Page 6 of 24

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

beyond the control of the Planning Coordinator or Transmission Planner that
prevent the implementation of a Corrective Action Plan in the required
timeframe, provided that the responsible entity documents the situation causing
the problem, alternatives evaluated, and takes actions to resolve the situation.
9.3. Make its Corrective Action Plan available to, and solicit feedback from, applicable
regulatory authorities or governing bodies responsible for retail electric service
issues.
9.4. Be permitted to have revisions to the Corrective Action Plan in subsequent
Extreme Temperature Assessments, provided that the planned Bulk Electric
System shall continue to meet the performance requirements of Table 1.
M9. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of each Corrective Action Plan
developed in accordance with Requirement R9 when the analysis of a benchmark
planning case indicates its portion of the Bulk Electric System is unable to meet
performance requirements for category P0 or P1 in Table 1. Evidence shall include
documentation of correspondence with applicable regulatory authorities or governing
bodies responsible for retail electric service issues and any revision history.
R10. Each responsible entity, as identified in Requirement R1, shall evaluate and document
possible actions designed to reduce the likelihood or mitigate the consequences and
adverse impacts of the event(s) if analyses conclude there could be instability,
uncontrolled separation, or Cascading within an Interconnection, for the following:
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
10.1. Table 1 P7 Contingencies in benchmark planning cases analyzed in accordance
with Requirement R8 Part 8.1.
10.2. Categories P0, P1, and P7 in Table 1 in sensitivity cases analyzed in accordance
with Requirement R8 Part 8.2.
M10. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation that it evaluated and documented
possible actions designed to reduce the likelihood or mitigate the consequences and
adverse impacts when the analyses conclude there could be instability, uncontrolled
separation, or Cascading within an Interconnection for Table 1 P7 Contingencies in
benchmark planning cases or categories P0, P1, or P7 in Table 1 in sensitivity cases.
R11. Each responsible entity, as identified in Requirement R1, shall provide its Extreme
Temperature Assessment results within 60 calendar days of a request to any
functional entity that has a reliability related need and submits a written request for
the information. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M11. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as email notices, documentation of updated web pages, or postal receipts
showing recipient, that it provided its Extreme Temperature Assessment to any

Final Draft of TPL-008-1
December 2024

Page 7 of 24

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

functional entity who has a reliability need within 60 calendar days of a written
request.

Final Draft of TPL-008-1
December 2024

Page 8 of 24

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

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 period(s) 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 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 responsible entity shall retain evidence of compliance with each
requirement in this standard for five calendar years or one complete
Extreme Temperature Assessment cycle, whichever is longer.

1.3. Compliance Monitoring and Enforcement Program: “Compliance Monitoring
Enforcement Program” or “CMEP” means, depending on the context (1) the
NERC Compliance Monitoring and Enforcement Program (Appendix 4C to the
NERC Rules of Procedure) or the Commission-approved program of a Regional
Entity, as applicable, or (2) the program, department or organization within
NERC or a Regional Entity that is responsible for performing compliance
monitoring and enforcement activities with respect to Registered Entities’
compliance with Reliability Standards.

Final Draft of TPL-008-1
December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events
Steady State & Stability:
a. Instability, uncontrolled separation, or Cascading within an Interconnection, defined in accordance with Requirement R6,
shall not occur.
b. Consequential Load Loss as well as generation loss is acceptable as a consequence of any event excluding P0.
c. Simulate the removal of all elements that Protection Systems and other controls are expected to automatically disconnect
for each event.
d. Simulate Normal Clearing unless otherwise specified.
e. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such
adjustments are executable within the time duration applicable to the Facility Ratings.
Steady State Only:
f. Applicable Facility Ratings shall not be exceeded.
g. System steady state voltages and post-Contingency voltage deviations shall meet the criteria identified in Requirement R5.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events

Category

P0
No
Contingency
P1
Single
Contingency

Initial
Condition

Normal
System

Normal
System

P7
Multiple
Contingency
(Common
Structure)

Normal
System

Final Draft of TPL-008-1
December 2024

Event1

Fault
Type3

None

N/A

Loss of one of the following:
1. Generator
2. Transmission Circuit
3. Transformer2
4. Shunt Device4

3Ø

5. Single Pole of a DC line

SLG

The loss of:
1. Any two adjacent (vertically
or horizontally) circuits on
common structure5
2. Loss of a bipolar DC line

SLG

Interruption
of Firm
Contingency
Transmission
BES Level
Service
Allowed

Non-Consequential Load Loss
Allowed
Benchmark
Planning
Cases

Sensitivity
Cases

N/A

Yes

No6

Yes

≥ 200 kV

Yes

Yes6

Yes

≥ 200 kV

Yes

Yes

Yes

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events
1. If the event analyzed involves BES elements at multiple System voltage levels, the lowest System voltage level of the
element(s) removed for the analyzed event determines the BES level of the event. For P7 events, the BES level of the event is
the highest System voltage level of the element(s) removed for the analyzed event.
2. For non-generator step up transformer outage events, the reference voltage, as used in footnote 1, applies to the low-side
winding (excluding tertiary windings). For generator and Generator Step Up transformer outage events, the reference
voltage applies to the BES connected voltage (high-side of the Generator Step Up transformer). Requirements which are
applicable to transformers also apply to variable frequency transformers and phase shifting transformers.
3. Unless specified otherwise, simulate Normal Clearing of faults. Single line to ground (SLG) or three-phase (3Ø) are the fault
types that must be evaluated in Stability simulations for the event described. A 3Ø or a double line to ground fault study
indicating the criteria are being met is sufficient evidence that a SLG condition would also meet the criteria.
4. Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
5. Excludes circuits that share a common structure for 1 mile or less.
6. Benchmark planning cases require the development of a Corrective Action Plan when the responsible entity’s portion of the
BES is unable to meet the performance requirements for categories P0 or P1. Additionally, in benchmark planning cases,
Non-Consequential Load Loss is not permitted for category P0 except where permitted as an interim solution in a Corrective
Action Plan in accordance with Requirement R9 Part 9.2.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels
Violation Severity Levels

R#
R1.

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed less than
or equal to six months late.

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than six months but less than
or equal to 12 months late.

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than 12 months but less than
or equal to 18 months late.

The Planning Coordinator, in
conjunction with its
Transmission Planner(s), failed
to identify individual and joint
responsibilities for completing
the Extreme Temperature
Assessment.
OR
The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than 18 months late.

R2.

N/A

Final Draft of TPL-008-1
December 2024

N/A

The Planning Coordinator
coordinated with all Planning
Coordinators within each
identified zone to identify one
common extreme heat and
one common extreme cold
benchmark temperature event
for completing the Extreme
Temperature Assessment, but
one of the identified events

The Planning Coordinator
coordinated with all Planning
Coordinators within each
identified zone to identify one
common extreme heat and
one common extreme cold
benchmark temperature event
for completing the Extreme
Temperature Assessment, but
both of the identified events

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

failed to meet all the criteria of failed to meet all of the criteria
Requirement R2.
of Requirement R2.
OR
The Planning Coordinator
failed to coordinate with all
Planning Coordinators within
each identified zone to identify
one common extreme heat
and one common extreme
cold benchmark temperature
event for completing the
Extreme Temperature
Assessment.
R3.

N/A

N/A

N/A

The Planning Coordinator did
not coordinate with all
Planning Coordinators within
each of its identified zone(s) to
implement a process for
developing benchmark
planning cases.
OR
The Planning Coordinator
coordinated with all Planning
Coordinators within each of its
identified zone(s) to
implement a process for
developing benchmark
planning cases, but the
process did not include all of
the required elements.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R4.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
did not use the process
developed in Requirement R3
to develop benchmark
planning cases or sensitivity
cases.
OR
The responsible entity, as
identified in Requirement R1,
used the process developed in
Requirement R3 to develop
benchmark planning cases and
sensitivity cases, but did not
use data consistent with that
provided in accordance with
the MOD-032 standard,
supplemented by other
sources as needed, for one or
more of the required cases.
OR
The responsible entity, as
identified in Requirement R1,
used the process developed in
Requirement R3 and data
consistent with that provided
in accordance with the MOD032 standard, supplemented
as needed, but failed to
develop one or more of the
required planning or sensitivity
cases.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R5.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
did not have criteria for
acceptable System steady
state voltage limits and postContingency voltage
deviations for completing the
Extreme Temperature
Assessment.

R6.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
failed to define or document
the criteria or methodology to
be used in the Extreme
Temperature Assessment to
identify instability,
uncontrolled separation, or
Cascading within an
Interconnection.

R7.

N/A

N/A

The responsible entity, as
identified in Requirement R1,
identified Contingencies for
each category in Table 1 that
are expected to produce more
severe System impacts on its
portion of the Bulk Electric
System, but did not include
the rationale for those
Contingencies selected for
evaluation as supporting
information.

The responsible entity, as
identified in Requirement R1,
did not identify Contingencies
for each category in Table 1
that are expected to produce
more severe System impacts
on its portion of the Bulk
Electric System.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for
one or more sensitivity cases
in accordance with
Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for
one or more benchmark
planning cases in accordance
with Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document results for one or
more of the sensitivity cases in
accordance with Requirement
R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document results for one or
more of the benchmark
planning cases in accordance
with Requirement R8.
OR
The responsible entity, as
identified in Requirement R1,
failed to complete steady state
or transient stability analyses
and document results in the
Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, in
accordance with Requirement
R8.

R9.

N/A

Final Draft of TPL-008-1
December 2024

N/A

The responsible entity, as
identified in Requirement R1,
developed a Corrective Action
Plan in accordance with
Requirement R9, but failed to
make its Corrective Action
Plan available to, or solicit
feedback from, applicable

The responsible entity, as
identified in Requirement R1,
failed to develop a Corrective
Action Plan when the
benchmark planning case
study results indicate the
System is unable to meet
performance requirements for

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regulatory authorities or
governing bodies responsible
for retail electric service
issues.

R10.

N/A

N/A

The responsible entity, as
identified in Requirement R1,
evaluated and documented
possible actions to reduce the
likelihood or mitigate the
consequences and adverse
impacts of the event(s) when
analyses conclude there could
be instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Part 10.1,
but failed to evaluate and
document possible actions
where required under
Requirement R10 Part 10.2.

the Table 1 P0 or P1
Contingencies.
OR
The responsible entity, as
identified in Requirement R1,
developed a Corrective Action
Plan, but it was missing one or
more of the elements of
Requirement R9 Part 9.1, 9.3
and 9.4 (as applicable).
The responsible entity, as
identified in Requirement R1,
evaluated and documented
possible actions to reduce the
likelihood or mitigate the
consequences and adverse
impacts of the event(s) when
analyses conclude there could
be instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Part 10.2,
but failed to evaluate and
document possible actions
where required under
Requirement R10 Part 10.1.
OR
The responsible entity, as
identified in Requirement R1,
failed to evaluate and
document possible actions to

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

reduce the likelihood or
mitigate the consequences
and adverse impacts of the
event(s) when analyses
conclude there could be
instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Parts 10.1
and 10.2.
R11.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 60 days but
less than or equal to 80 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 80 days but
less than or equal to 100 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 100 days but
less than or equal to 120 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 120 days
following the request.
OR
The responsible entity, as
identified in Requirement R1,
did not provide its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who submitted a written
request for the information.

D. Regional Variances
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December 2024

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None.

E. Associated Documents
•

Implementation Plan for Project 2023-07

•

Technical Rationale Document

•

Consideration of Issues and Directives for FERC Order 896.

•

ERO Benchmark Event Library

•

TPL-008 Data Library Read Me

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December 2024

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Version History
Version
1

Date
TBD

Final Draft of TPL-008-1
December 2024

Action

Change
Tracking

Addressing FERC Order 896

New Standard

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TPL-008-1 Supplemental Material

Attachment 1: Extreme Temperature Assessment Zones

The table below lists the zones to be used in the Extreme Temperature Assessment and
identifies the Planning Coordinators that belong to each zone. In accordance with Requirement
R2, each Planning Coordinator is required to identify the zone(s) to which it belongs. Planning
Coordinators, in different zones within a broader planning region, may use the same
benchmark temperature events for their respective benchmark planning cases, provided the
benchmark temperature events meet the criteria of Requirement R2 for each zone.
Zone
MISO North

MISO South
SPP North
SPP South
PJM
New England
New York
SERC
Florida
Central Canada
Ontario
Maritimes

Southwest
Pacific Northwest

Final Draft of TPL-008-1
December 2024

Planning Coordinators

Eastern Interconnection
Planning Coordinator(s) in MISO that serve
portions of MISO in Montana, North Dakota,
South Dakota, Minnesota, Iowa, Wisconsin,
Michigan, Indiana, Illinois, Missouri, and
Kentucky
Planning Coordinator(s) in MISO that serve
portions of Arkansas, Mississippi, Louisiana, and
Texas
Planning Coordinator(s) in portions of SPP that
serve Iowa, Montana, Nebraska, North Dakota,
and South Dakota.
Planning Coordinator(s) in portions of SPP that
serve Arkansas, Kansas, Louisiana, Missouri, New
Mexico, Oklahoma, and Texas.
Planning Coordinator(s) that serves PJM
Planning Coordinator(s) in NPCC that serve the six
New England States
Planning Coordinator(s) in NPCC that serve New
York
Planning Coordinator(s) in SERC, excluding those
that serve Florida and those in MISO, SPP, and
PJM
Planning Coordinator(s) in SERC that serve Florida
Planning Coordinator(s) that serve Saskatchewan
and Manitoba region of MRO
Planning Coordinator(s) in NPCC that serve
Ontario
Planning Coordinator(s) in NPCC that primarily
serve New Brunswick, Nova Scotia, Prince Edward
Island, and Northern Maine
Western Interconnection
Planning Coordinator(s) in the Southwest region
of WECC, including El Paso in West Texas
Planning Coordinator(s) in the Pacific Northwest
region of WECC

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TPL-008-1 Supplemental Material

Great Basin
Rocky Mountain
California/Mexico
Western Canada
ERCOT
Quebec

Final Draft of TPL-008-1
December 2024

Zone

Planning Coordinators
Planning Coordinator(s) in the Great Basin region
of WECC
Planning Coordinator(s) in the Rocky Mountain
region of WECC
Planning Coordinator(s) in the California/Mexico
region of WECC
Planning Coordinator(s) that primarily serve
British Columbia and Alberta region of WECC
ERCOT Interconnection
Planning Coordinator(s) in Texas that are part of
the ERCOT Interconnection
Quebec Interconnection
Planning Coordinator(s) that serve Quebec in the
NPCC Region.

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TPL-008-1 Supplemental Material

The map below depicts an approximation of the zones to be used in the Extreme Temperature
Assessment and is provided as a visual aid; to the extent that there is a conflict between the
map and the table, the table controls. This map is not to be used for compliance purposes.
TPL-008-1 Weather Zones Map

Final Draft of TPL-008-1
December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

This is the fourth draft of the proposed standard posted for a 15-day formal comment period
with additional ballot.
Completed Actions

Date

Standards Committee approved Standard Authorization Request (SAR)
for posting

July 19, 2023

SAR posted for comment

August 8–September 27,
2023

45-day formal comment period with initial ballot

March 20–May 3, 2024

38-day formal comment period with additional ballot

July 16–August 22, 2024

15-day formal comment period with additional ballot

October 7–21, 2024

Anticipated Actions

Date

15-day formal comment period with additional ballot

November 7–21, 2024

5-day final ballot

December 2–6, 2024

Board adoption

December 10, 2024

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December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

New or Modified Term(s) Used in NERC Reliability Standards

This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):

Extreme Temperature Assessment – Documented evaluation of future Bulk Electric System
performance for extreme heat and extreme cold benchmark temperature events.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements for Extreme
Temperature Events

2.

Number:

TPL-008-1

3.

Purpose:

Establish Transmission system planning performance requirements to
develop a Bulk Power System (BPS) that will operate reliably during
extreme heat and extreme cold temperature events.

4.

Applicability:
4.1. Functional Entities:
4.1.1. Transmission Planner
4.1.2. Planning Coordinator

5.

Effective Date: See Implementation Plan for Project 2023-07.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

B. Requirements and Measures
R1. Each Planning Coordinator shall identify, in conjunction with its Transmission
Planner(s), each entity’s individual and joint responsibilities for completing the
Extreme Temperature Assessment, which shall include each of the responsibilities
described in Requirements R2 through R11. Each responsible entity shall complete its
responsibilities such that the Extreme Temperature Assessment is completed at least
once every five calendar years. [Violation Risk Factor: Lower] [Time Horizon: Long-term
Planning]
M1. Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
provide dated documentation of each entity’s individual and joint responsibilities,
such as meeting minutes, agreements, copies of procedures, or protocols in effect
between entities or between departments of a vertically integrated system, or email
correspondence that identifies an agreement has been reached on individual and joint
responsibilities for completing the Extreme Temperature Assessment, and that these
responsibilities were completed such that the Extreme Temperature Assessment was
completed once every five calendar years.
R2. Each Planning Coordinator shall identify the zone(s) to which the Planning Coordinator
belongs to under Attachment 1 and shall coordinate with all Planning Coordinators
within each of its identified zone(s), to identify one common extreme heat benchmark
temperature event and one common extreme cold benchmark temperature event for
each of its identified zone(s) when completing the Extreme Temperature Assessment.
The benchmark temperature events shall be obtained from the benchmark library
maintained by the ERO or developed by the Planning Coordinators. Each benchmark
temperature event identified by the Planning Coordinators shall: [Violation Risk
Factor: High] [Time Horizon: Long-term Planning]
2.1. Consider no less than a 40-year period of temperature data ending no more than
five years prior to the time the benchmark temperature events are selected; and
2.2. Represent one of the 20 most extreme temperature conditions based on the
three-day rolling average of daily maximum (heat) or daily minimum (cold)
temperature across the zone.
M2. Each Planning Coordinator shall have evidence in either electronic or hard copy format
that it identified the zone(s) to which it belongs to, under Attachment 1, and that it
coordinated with all other Planning Coordinators within each of its identified zone(s)
to select identify one common extreme heat benchmark temperature event and one
common extreme cold benchmark temperature event meeting the criteria of
Requirement R2 for each of their identified zone(s) when completing the Extreme
Temperature Assessment.
R3. Each Planning Coordinator shall coordinate with all Planning Coordinators within each
of its zone(s) identified in Requirement R2, to implement a process for developing
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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

benchmark planning cases for the Extreme Temperature Assessment that represent
the benchmark temperature events selected in Requirement R2 and sensitivity cases
to demonstrate the impact of changes to the basic assumptions used in the
benchmark planning cases. This process shall include the following: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
3.1. Selection of System models within the Long-Term Transmission Planning Horizon
to form the basis for the benchmark planning cases.
3.2. Forecasted seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers within the zone.
3.3. Assumed seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers in areas outside the zone, as needed.
3.4. Identification of changes to at least one of the following conditions for sensitivity
cases: generation, real and reactive forecasted Load, or transfers.
M3. Each Planning Coordinator shall have dated evidence that it implemented a process
for coordinating the development of benchmark planning cases and sensitivity cases
for the Extreme Temperature Assessment as specified in Requirement R3.
R4. Each responsible entity, as identified in Requirement R1, shall use the coordination
process developed in Requirement R3 and data consistent with that provided in
accordance with the MOD-032 standard, supplemented by other sources as needed,
to develop the following and establish category P0 as the normal System condition in
Table 1: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. One common extreme heat and one common extreme cold benchmark planning
case.
4.2. One common extreme heat and one common extreme cold sensitivity case.
M4. Each responsible entity, as identified in Requirement R1, shall have dated evidence in
either electronic or hard copy format that it developed benchmark planning cases and
sensitivity cases in accordance with Requirement R4.
R5. Each responsible entity, as identified in Requirement R1, shall have criteria for
acceptable System steady state voltage limits and post-Contingency voltage deviations
for completing the Extreme Temperature Assessment. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning]
M5. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of the documentation, specifying the criteria for
acceptable System steady state voltage limits and post-Contingency voltage deviations
for completing the Extreme Temperature Assessment.
R6. Each responsible entity, as identified in Requirement R1, shall define and document
the criteria or methodology to be used in the Extreme Temperature Assessment to
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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

identify instability, uncontrolled separation, or Cascading within an Interconnection.
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
M6. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, specifying the criteria or
methodology to be used in the Extreme Temperature Assessment to identify
instability, uncontrolled separation, or Cascading within an Interconnection in
accordance with Requirement R6.
R7. Each responsible entity, as identified in Requirement R1, shall identify the
Contingencies for each category in Table 1 that are expected to produce more severe
System impacts on its portion of the Bulk Electric System. The rationale for those
Contingencies selected for evaluation shall be available as supporting information.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M7. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of the Contingencies for each
category in Table 1 that are expected to produce more severe System impacts on its
portion of the Bulk Electric System along with supporting rationale.
R8. Each responsible entity, as identified in Requirement R1, shall complete steady state
and transient stability analyses in the Extreme Temperature Assessment using the
Contingencies identified in Requirement R7, and shall document the assumptions and
results. Steady state and transient stability analyses shall be performed for the
following: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
8.1. Benchmark planning cases developed in accordance with Requirement R4 Part
4.1.
8.2. Sensitivity cases developed in accordance with Requirement R4 Part 4.2.
M8. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of the assumptions and results of
the steady state and transient stability analyses completed in the Extreme
Temperature Assessment.
R9. Each responsible entity, as identified in Requirement R1, shall develop a Corrective
Action Plan(s) when the analysis of a benchmark planning case, in accordance with
Requirement R8 Part 8.1, indicates its portion of the Bulk Electric System is unable to
meet performance requirements for category P0 or P1 in Table 1. For each Corrective
Action Plan, the responsible entity shall: [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
9.1. Document alternative(s) considered when Non-Consequential Load Loss is
utilized as an element of a Corrective Action Plan for a Table 1 P1 Contingency.
9.2. Be permitted to utilize Non-Consequential Load Loss as an interim solution,
which normally is not permitted for category P0 in Table 1 for situations that are
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December 2024

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beyond the control of the Planning Coordinator or Transmission Planner that
prevent the implementation of a Corrective Action Plan in the required
timeframe, provided that the responsible entity documents the situation causing
the problem, alternatives evaluated, and takes actions to resolve the situation.
9.3. Make its Corrective Action Plan available to, and solicit feedback from, applicable
regulatory authorities or governing bodies responsible for retail electric service
issues.
9.4. Be permitted to have revisions to the Corrective Action Plan in subsequent
Extreme Temperature Assessments, provided that the planned Bulk Electric
System shall continue to meet the performance requirements of Table 1.
M9. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of each Corrective Action Plan
developed in accordance with Requirement R9 when the analysis of a benchmark
planning case indicates its portion of the Bulk Electric System is unable to meet
performance requirements for category P0 or P1 in Table 1. Evidence shall include
documentation of correspondence with applicable regulatory authorities or governing
bodies responsible for retail electric service issues and any revision history.
R10. Each responsible entity, as identified in Requirement R1, shall evaluate and document
possible actions designed to reduce the likelihood or mitigate the consequences and
adverse impacts of the event(s) if analyses conclude there could be instability,
uncontrolled separation, or Cascading within an Interconnection, for the following:
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
10.1. Table 1 P7 Contingencies in benchmark planning cases analyzed in accordance
with Requirement R8 Part 8.1.
10.2. Categories P0, P1, and P7 in Table 1 in sensitivity cases analyzed in accordance
with Requirement R8 Part 8.2.
M10. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation that it evaluated and documented
possible actions designed to reduce the likelihood or mitigate the consequences and
adverse impacts when the analyses conclude there could be instability, uncontrolled
separation, or Cascading within an Interconnection for Table 1 P7 Contingencies in
benchmark planning cases or categories P0, P1, or P7 in Table 1 in sensitivity cases.
R11. Each responsible entity, as identified in Requirement R1, shall provide its Extreme
Temperature Assessment results within 60 calendar days of a request to any
functional entity that has a reliability related need and submits a written request for
the information. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M11. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as email notices, documentation of updated web pages, or postal receipts
showing recipient, that it provided its Extreme Temperature Assessment to any

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

functional entity who has a reliability need within 60 calendar days of a written
request.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

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 period(s) 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 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 responsible entity shall retain evidence of compliance with each
requirement in this standard for five calendar years or one complete
Extreme Temperature Assessment cycle, whichever is longer.

1.3. Compliance Monitoring and Enforcement Program: “Compliance Monitoring
Enforcement Program” or “CMEP” means, depending on the context (1) the
NERC Compliance Monitoring and Enforcement Program (Appendix 4C to the
NERC Rules of Procedure) or the Commission-approved program of a Regional
Entity, as applicable, or (2) the program, department or organization within
NERC or a Regional Entity that is responsible for performing compliance
monitoring and enforcement activities with respect to Registered Entities’
compliance with Reliability Standards.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events
Steady State & Stability:
a. Instability, uncontrolled separation, or Cascading within an Interconnection, defined in accordance with Requirement R6,
shall not occur.
b. Consequential Load Loss as well as generation loss is acceptable as a consequence of any event excluding P0.
c. Simulate the removal of all elements that Protection Systems and other controls are expected to automatically disconnect
for each event.
d. Simulate Normal Clearing unless otherwise specified.
e. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such
adjustments are executable within the time duration applicable to the Facility Ratings.
Steady State Only:
f. Applicable Facility Ratings shall not be exceeded.
g. System steady state voltages and post-Contingency voltage deviations shall meet the criteria identified in Requirement R5.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events

Category

P0
No
Contingency
P1
Single
Contingency

Initial
Condition

Normal
System

Normal
System

P7
Multiple
Contingency
(Common
Structure)

Draft 4 of TPL-008-1
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Normal
System

Event1

Fault
Type3

None

N/A

Loss of one of the following:
1. Generator
2. Transmission Circuit
3. Transformer2
4. Shunt Device4

3Ø

5. Single Pole of a DC line

SLG

The loss of:
1. Any two adjacent (vertically
or horizontally) circuits on
common structure5
2. Loss of a bipolar DC line

SLG

Interruption
of Firm
Contingency
Transmission
BES Level
Service
Allowed

Non-Consequential Load Loss
Allowed
Benchmark
Planning
Cases

Sensitivity
Cases

N/A

Yes

No6

Yes

≥ 200 kV

Yes

Yes6

Yes

≥ 200 kV

Yes

Yes

Yes

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events
1. If the event analyzed involves BES elements at multiple System voltage levels, the lowest System voltage level of the
element(s) removed for the analyzed event determines the BES level of the event. For P7 events, the BES level of the event is
the highest System voltage level of the element(s) removed for the analyzed event.
2. For non-generator step up transformer outage events, the reference voltage, as used in footnote 1, applies to the low-side
winding (excluding tertiary windings). For generator and Generator Step Up transformer outage events, the reference
voltage applies to the BES connected voltage (high-side of the Generator Step Up transformer). Requirements which are
applicable to transformers also apply to variable frequency transformers and phase shifting transformers.
3. Unless specified otherwise, simulate Normal Clearing of faults. Single line to ground (SLG) or three-phase (3Ø) are the fault
types that must be evaluated in Stability simulations for the event described. A 3Ø or a double line to ground fault study
indicating the criteria are being met is sufficient evidence that a SLG condition would also meet the criteria.
4. Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
5. Excludes circuits that share a common structure for 1 mile or less.
6. Benchmark planning cases require the development of a Corrective Action Plan when the responsible entity’s portion of the
BES is unable to meet the performance requirements for categories P0 or P1. Additionally, in benchmark planning cases,
Non-Consequential Load Loss is not permitted for category P0 except where permitted as an interim solution in a Corrective
Action Plan in accordance with Requirement R9 Part 9.2.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels
Violation Severity Levels

R#
R1.

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed less than
or equal to six months late.

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than six months but less than
or equal to 12 months late.

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than 12 months but less than
or equal to 18 months late.

The Planning Coordinator, in
conjunction with its
Transmission Planner(s), failed
to identify individual and joint
responsibilities for completing
the Extreme Temperature
Assessment.
OR
The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than 18 months late.

R2.

N/A

Draft 4 of TPL-008-1
December 2024

N/A

The Planning Coordinator
coordinated with all Planning
Coordinators within each
identified zone to identify one
common extreme heat and
one common extreme cold
benchmark temperature event
for completing the Extreme
Temperature Assessment, but
one of the identified events

The Planning Coordinator
coordinated with all Planning
Coordinators within each
identified zone to identify one
common extreme heat and
one common extreme cold
benchmark temperature event
for completing the Extreme
Temperature Assessment, but
both of the identified events

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

failed to meet all the criteria of failed to meet all of the criteria
Requirement R2.
of Requirement R2.
OR
The Planning Coordinator
failed to coordinate with all
Planning Coordinators within
each identified zone to identify
one common extreme heat
and one common extreme
cold benchmark temperature
event for completing the
Extreme Temperature
Assessment.
R3.

N/A

N/A

N/A

The Planning Coordinator did
not coordinate with all
Planning Coordinators within
each of its identified zone(s) to
implement a process for
developing benchmark
planning cases.
OR
The Planning Coordinator
coordinated with all Planning
Coordinators within each of its
identified zone(s) to
implement a process for
developing benchmark
planning cases, but the
process did not include all of
the required elements.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R4.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
did not use the coordination
process developed in
Requirement R3 to develop
benchmark planning cases or
sensitivity cases.
OR
The responsible entity, as
identified in Requirement R1,
used the coordination process
developed in Requirement R3
to develop benchmark
planning cases and sensitivity
cases, but did not use data
consistent with that provided
in accordance with the MOD032 standard, supplemented
by other sources as needed,
for one or more of the
required cases.
OR
The responsible entity, as
identified in Requirement R1,
used the coordination process
developed in Requirement R3
and data consistent with that
provided in accordance with
the MOD-032 standard,
supplemented as needed, but
failed to develop one or more

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

of the required planning or
sensitivity cases.
R5.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
did not have criteria for
acceptable System steady
state voltage limits and postContingency voltage
deviations for completing the
Extreme Temperature
Assessment.

R6.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
failed to define or document
the criteria or methodology to
be used in the Extreme
Temperature Assessment to
identify instability,
uncontrolled separation, or
Cascading within an
Interconnection.

R7.

N/A

N/A

The responsible entity, as
identified in Requirement R1,
identified Contingencies for
each category in Table 1 that
are expected to produce more
severe System impacts on its
portion of the Bulk Electric
System, but did not include
the rationale for those
Contingencies selected for

The responsible entity, as
identified in Requirement R1,
did not identify Contingencies
for each category in Table 1
that are expected to produce
more severe System impacts
on its portion of the Bulk
Electric System.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

evaluation as supporting
information.
R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for
one or more sensitivity cases
in accordance with
Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for
one or more benchmark
planning cases in accordance
with Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
evaluate and document results
for one or more of the
sensitivity cases in accordance
with Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
evaluate and document results
for one or more of the
benchmark planning cases in
accordance with Requirement
R8.
OR
The responsible entity, as
identified in Requirement R1,
failed to complete steady state
or transient stability analyses
and document results in the
Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, in
accordance with Requirement
R8.

R9.

N/A

Draft 4 of TPL-008-1
December 2024

N/A

The responsible entity, as
identified in Requirement R1,
developed a Corrective Action
Plan in accordance with
Requirement R9, but failed to

The responsible entity, as
identified in Requirement R1,
failed to develop a Corrective
Action Plan when the
benchmark planning case
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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

make its Corrective Action
Plan available to, or solicit
feedback from, applicable
regulatory authorities or
governing bodies responsible
for retail electric service
issues.

R10.

N/A

N/A

The responsible entity, as
identified in Requirement R1,
evaluated and documented
possible actions to reduce the
likelihood or mitigate the
consequences and adverse
impacts of the event(s) when
analyses conclude there could
be instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Part 10.1,
but failed to evaluate and
document possible actions
where required under
Requirement R10 Part 10.2.

study results indicate the
System is unable to meet
performance requirements for
the Table 1 P0 or P1
Contingencies.
OR
The responsible entity, as
identified in Requirement R1,
developed a Corrective Action
Plan, but it was missing one or
more of the elements of
Requirement R9 Part 9.1, 9.3
and 9.4 (as applicable).
The responsible entity, as
identified in Requirement R1,
evaluated and documented
possible actions to reduce the
likelihood or mitigate the
consequences and adverse
impacts of the event(s) when
analyses conclude there could
be instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Part 10.2,
but failed to evaluate and
document possible actions
where required under
Requirement R10 Part 10.1.
OR

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

The responsible entity, as
identified in Requirement R1,
failed to evaluate and
document possible actions to
reduce the likelihood or
mitigate the consequences
and adverse impacts of the
event(s) when analyses
conclude there could be
instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Parts 10.1
and 10.2.
R11.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 60 days but
less than or equal to 80 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 80 days but
less than or equal to 100 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 100 days but
less than or equal to 120 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 120 days
following the request.
OR
The responsible entity, as
identified in Requirement R1,
did not provide its Extreme
Temperature Assessment
results to functional entities
having a reliability related

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

need who submitted a written
request for the information.

D. Regional Variances
None.

E. Associated Documents
•

Implementation Plan for Project 2023-07

•

Technical Rationale Document

•

Consideration of Issues and Directives for FERC Order 896.

•

ERO Benchmark Event Library

•

TPL-008 Data Library Read Me

Draft 4 of TPL-008-1
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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Version History
Version
1

Draft 4 of TPL-008-1
December 2024

Date
TBD

Action

Change
Tracking

Addressing FERC Order 896

New Standard

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TPL-008-1 Supplemental Material

Attachment 1: Extreme Temperature Assessment Zones

The table below lists the zones to be used in the Extreme Temperature Assessment and
identifies the Planning Coordinators that belong to each zone. In accordance with Requirement
R2, each Planning Coordinator is required to identify the zone(s) to which it belongs. Planning
Coordinators in different zones within a broader planning region may use the same benchmark
temperature events for their respective benchmark planning cases, provided the benchmark
temperature events meet the criteria of Requirement R2 for each zone.
Zone
MISO North

MISO South
SPP North
SPP South
PJM
New England
New York
SERC
Florida
Central Canada
Ontario
Maritimes

WECC Southwest
Pacific Northwest

Draft 4 of TPL-008-1
December 2024

Planning Coordinators

Eastern Interconnection
Planning Coordinator(s) in MISO that serve
portions of MISO in Montana, North Dakota,
South Dakota, Minnesota, Iowa, Wisconsin,
Michigan, Indiana, Illinois, Missouri, and
Kentucky
Planning Coordinator(s) in MISO that serve
portions of Arkansas, Mississippi, Louisiana, and
Texas
Planning Coordinator(s) in portions of SPP that
serve Iowa, Montana, Nebraska, North Dakota,
and South Dakota.
Planning Coordinator(s) in portions of SPP that
serve Arkansas, Kansas, Louisiana, Missouri, New
Mexico, Oklahoma, and Texas.
Planning Coordinator(s) that serves PJM
Planning Coordinator(s) in NPCC that serve the six
New England States
Planning Coordinator(s) in NPCC that serve New
York
Planning Coordinator(s) in SERC, excluding those
that serve Florida and those in MISO, SPP, and
PJM
Planning Coordinator(s) in SERC that serve Florida
Planning Coordinator(s) that serve Saskatchewan
and Manitoba region of MRO
Planning Coordinator(s) in NPCC that serve
Ontario
Planning Coordinator(s) in NPCC that primarily
serve New Brunswick, Nova Scotia, Prince Edward
Island, and Northern Maine
Western Interconnection
Planning Coordinator(s) in the Southwest region
of WECC, including El Paso in West Texas
Planning Coordinator(s) in the Pacific Northwest
region of WECC

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TPL-008-1 Supplemental Material

Great Basin
Rocky Mountain
California/Mexico
Western Canada
ERCOT
Quebec

Draft 4 of TPL-008-1
December 2024

Zone

Planning Coordinators
Planning Coordinator(s) in the Great Basin region
of WECC
Planning Coordinator(s) in the Rocky Mountain
region of WECC
Planning Coordinator(s) in the California/Mexico
region of WECC
Planning Coordinator(s) that primarily serve
British Columbia and Alberta region of WECC
ERCOT Interconnection
Planning Coordinator(s) in Texas that are part of
the ERCOT Interconnection
Quebec Interconnection
Planning Coordinator(s) that serve Quebec in the
NPCC Region.

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TPL-008-1 Supplemental Material

The map below depicts an approximation of the zones to be used in the Extreme Temperature
Assessment and is provided as a visual aid; to the extent that there is a conflict between the
map and the table, the table controls. This map is not to be used for compliance purposes.
TPL-008-1 Weather Zones Map

Draft 4 of TPL-008-1
December 2024

Page 24 of 24

Implementation Plan

Project 2023-07 Transmission System Planning Performance
Requirements for Extreme Weather
Reliability Standard TPL-008-1
Applicable Standard
•

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature
Events

Requested Retirement
•

Not applicable

Prerequisite Standard
•

Not applicable

Applicable Entities
•

Planning Coordinators

•

Transmission Planners

New Term in the NERC Glossary of Terms

This section includes all newly defined, revised, or retired terms used or eliminated in the NERC Reliability
Standard. New or revised definitions listed below become approved when the proposed standard is
approved. When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
•

Extreme Temperature Assessment – Documented evaluation of future Bulk Electric System
performance for extreme heat and extreme cold benchmark temperature events.

Background

On June 15, 2023, the U.S. Federal Energy Regulatory Commission (“FERC”) issued Order No. 896, a final
rule directing NERC to develop a new or modified Reliability Standard to address the lack of a long-term
planning requirement(s) for extreme heat and cold weather events.1 Specifically, FERC directed NERC to
develop modifications to Reliability Standard TPL-001-5.1 or develop a new Reliability Standard that
requires the following: (1) development of benchmark planning cases based on major prior extreme heat
and cold weather events and/or meteorological projections; (2) planning for extreme heat and cold weather
1

Transmission System Planning Requirements for Extreme Weather, Order No. 896, 183 FERC ¶ 61,191 (2023).

RELIABILITY | RESILIENCE | SECURITY

events using steady state and transient stability analyses expanded to cover a range of extreme weather
scenarios including the expected resource mix’s availability during extreme heat and cold weather
conditions, and including the wide-area impacts of extreme heat and cold weather; and (3) development
of Corrective Action Plans that mitigate any instances where performance requirements for extreme heat
and cold weather events are not met. FERC further directed NERC to ensure that the proposed new or
modified Reliability Standard becomes mandatory and enforceable beginning no later than 12 months from
the effective date of FERC approval.

General Considerations

Proposed Reliability Standard TPL-008-1 would require the performance of an Extreme Temperature
Assessment at least once every five calendar years (Requirement R1). This implementation plan provides a
staggered approach for the performance of the first Extreme Temperature Assessment, with phased-in
compliance dates beginning 12 months from the effective date of regulatory approval consistent with Order
No. 896. For subsequent Extreme Temperature Assessments, entities may establish timeframes appropriate
to their facts and circumstances for carrying out their responsibilities under the standard, provided that the
Extreme Temperature Assessment is completed no later than five calendar years following the previous
Extreme Temperature Assessment.

Effective Date

The effective date for the proposed Reliability Standard is provided below. Where the standard drafting
team identified the need for a longer implementation period for compliance with a particular section of the
proposed Reliability Standard (e.g., an entire Requirement or a portion thereof), the additional time for
compliance with that section is specified below. These phased-in compliance dates represent the dates that
entities must begin to comply with that particular section of the Reliability Standard, even where the
Reliability Standard goes into effect at an earlier date.
TPL-008-1 and Definition

Where approval by an applicable governmental authority is required, the standard and definition of
Extreme Temperature Assessment shall become effective on the first day of the first calendar quarter that
is twelve (12) 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 twelve (12) months after the date the standard
and definition of Extreme Temperature Assessment is adopted by the NERC Board of Trustees, or as
otherwise provided for in that jurisdiction.

Phased-In Compliance Dates

Compliance Date for TPL-008-1 Requirement R1

Entities shall be required to comply with Requirement R1, pertaining to the identification of individual and
joint responsibilities for completing the Extreme Temperature Assessment, upon the effective date of
Reliability Standard TPL-008-1.

Implementation Plan
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | December 2024

2

Compliance Date for TPL-008-1 Requirements R2, R3, R4, R5, R6

Entities shall not be required to comply with Requirements R2, R3, R4, R5, and R6 until twenty-four (24)
months after the effective date of Reliability Standard TPL-008-1.
Compliance Date for TPL-008-1 Requirements R7, R8, R9, R10, R11

Entities shall not be required to comply with Requirements R7, R8, R9, R10, and R11 until forty-eight (48)
months after the effective date of Reliability Standard TPL-008-1.
Figure 1: Implementation Plan, Demonstrating Effective Date
and Phased-in Compliance Dates from the effective date of
the governmental authority’s order approving this standard

Initial Performance of Periodic Requirements

Entities shall complete the Extreme Temperature Assessment no later than forty-eight (48) months after
the effective date of Reliability Standard TPL-008-1. Subsequent Extreme Temperature Assessments shall
be completed by no later than five calendar years following the completion of the previous Extreme
Temperature Assessment.

Implementation Plan
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | December 2024

3

Technical Rationale and
Justification for TPL-008-1
Project 2023-07 Transmission Planning
Performance Requirements for Extreme
Weather
December 2024

RELIABILITY | RESILIENCE | SECURITY

NERC | Report Title | Report Date
I

Table of Contents
Preface ........................................................................................................................................................................... iii
Introduction ................................................................................................................................................................... iv
Defined Terms ................................................................................................................................................................. 5
TPL-008-1 Standard ......................................................................................................................................................... 6
Requirement R1 .............................................................................................................................................................. 7
Requirement R2 .............................................................................................................................................................. 8
Requirement R3 ............................................................................................................................................................ 10
Requirement R4 ............................................................................................................................................................ 11
Requirement R5 ............................................................................................................................................................ 12
Requirement R6 ............................................................................................................................................................ 13
Requirement R7 ............................................................................................................................................................ 14
Requirement R8 ............................................................................................................................................................ 19
Requirement R9 ............................................................................................................................................................ 20
Requirement R10 .......................................................................................................................................................... 21
Requirement R11 .......................................................................................................................................................... 22

NERC | Technical Rationale and Justification for TPL-008-1 | November 2024
ii

Preface
Electricity is a key component of the fabric of modern society and the Electric Reliability Organization (ERO) Enterprise
serves to strengthen that fabric. The vision for the ERO Enterprise, which is comprised of NERC and the six Regional
Entities, is a highly reliable, resilient, and secure North American bulk power system (BPS). Our mission is to assure
the effective and efficient reduction of risks to the reliability and security of the grid.
Reliability | Resilience | Security
Because nearly 400 million citizens in North America are counting on us
The North American BPS is made up of six Regional Entities as shown on the map and in the corresponding table
below. The multicolored area denotes overlap as some load-serving entities participate in one Regional Entity while
associated Transmission Owners/Operators participate in another.

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

Texas RE

Texas Reliability Entity

WECC

WECC

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Introduction
This document explains the technical rationale and justification for the proposed Reliability Standard TPL-008-1. It
provides stakeholders and the ERO Enterprise with an understanding of the technology and technical requirements
in the Reliability Standard. This Technical Rationale and Justification for TPL-008-1 is not a Reliability Standard and
should not be considered mandatory and enforceable.

Background

On June 15, 2023, FERC issued FERC Order No. 896 that acknowledges the “challenges associated with planning for
extreme heat and cold weather events, particularly those that occur during periods when the Bulk-Power System
must meet unexpectedly high demand. Extreme heat and cold weather events have occurred with greater frequency
in recent years and are projected to occur with even greater frequency in the future. These events have shown that
load shed during extreme temperatures result in unacceptable risk to life and have extreme economic impact. As
such, the impact of concurrent failures of Bulk-Power System (BPS) generation and transmission equipment and the
potential for cascading outages that may be caused by extreme heat and cold weather events should be studied and
corrective actions should be identified and implemented.” 1
Therefore, the Commission directed in FERC Order No. 896 to develop a new or modified Reliability Standard to
address a lack of long-term planning requirement(s) for extreme heat and cold weather events. Specifically, FERC
directed NERC to develop modifications to Reliability Standard TPL-001-5.1 or a new Reliability Standard, to require
the following: (1) development of benchmark planning cases based on major prior extreme heat and cold weather
events and/or meteorological projections; (2) planning for extreme heat and cold weather events using steady state
and transient stability analyses expanded to cover a range of extreme weather scenarios including the expected
resource mix's availability during extreme heat and cold weather conditions, and including the wide-area impacts of
extreme heat and cold weather; and (3) development of corrective action plans that mitigate any instances where
performance requirements for extreme heat and cold weather events are not met.

1

N. Am. Elec. Reliability Corp., 183 FERC ¶ 61,191 (2023) (FERC Order), Final Rule. eLibrary | File List (ferc.gov)
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Defined Terms
The Drafting Team (DT) defined one term to be added to the NERC Glossary of Terms to make the requirements easier
to read and understand.
Extreme Temperature Assessment
Documented evaluation of future Bulk Electric System performance for extreme heat and extreme cold
benchmark temperature events.
The definition of Extreme Temperature Assessment was developed by the DT to limit wordiness throughout the
requirements.

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TPL-008-1 Standard
The FERC Order No. 896 directed NERC to submit a new Reliability Standard or modifications to Reliability Standard
TPL-001-5.1 to address the concerns pertaining to transmission system planning for extreme heat and cold weather
events that impact the Reliable Operation of the Bulk-Power System.
The SDT determined that a new Reliability Standard was the cleanest way to address FERC’s directives versus
modifying Reliability Standard TPL-001-5.1. While the TPL-008-1 standard uses similar requirements, this allows
industry to have one standard that focuses on extreme heat and extreme cold benchmark temperature events.
The purpose of TPL-008-1 is to “Establish Transmission system planning performance requirements to develop a Bulk
Power System (BPS) that will operate reliably during extreme heat and extreme cold temperature events.” The
directives in FERC Order No. 896 pertain to the reliable operation of the BPS, and the requirements of TPL-008-1
support that by ensuring Planning Coordinators and Transmission Planners are planning their portions of the Bulk
Electric System (BES) to meet performance requirements in extreme heat and extreme cold benchmark temperature
events.

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Requirement R1
Requirement R1 requires each Planning Coordinator (PC) and the Transmission Planner(s) (TP) within the PC’s
footprint to identify each entity’s individual and joint responsibilities when completing the Extreme Temperature
Assessment at least once every five calendar years. Due to significant level of data collection and coordination
between the Planning Coordinator(s) and Transmission Planner(s) for the potential wide-area extreme heat and
extreme cold benchmark events, as well as the need to document the assumptions and study results, the drafting
team opined that completing the Extreme Temperature Assessment once every five calendar years is a reasonable
timeframe to allow responsible entities to coordinate, prepare, perform, and document the study results. To the
extent that responsible entities want to complete more than one set of the Extreme Temperature Assessment for an
extreme heat and extreme cold benchmark event, they can do so, but the minimum requirement is once every five
calendar years to complete one set of the Extreme Temperature Assessment.
The purpose of this requirement is to have the PC and its TP(s) identify their individual and joint responsibilities for
the following activities:
•

Identifying the PC’s zone(s) and coordinating with all PCs in each of its identified zone(s) to select one
common extreme heat benchmark temperature event and one common extreme cold benchmark
temperature event (Requirement R2),

•

Implementing a process for developing benchmark planning cases and sensitivity cases (Requirement R3),

•

Developing benchmark planning cases and sensitivity cases (Requirement R4),

•

Having acceptable criteria (Requirements R5 and R6),

•

Identifying Contingencies for evaluation (Requirement R7),

•

Performing steady state and transient stability analyses (Requirement R8),

•

Developing Corrective Action Plans when required (Requirement R9),

•

Evaluating and documenting possible actions for performance deficiencies that do not require Corrective
Action Plans (Requirement R10), and

•

Providing study results to any functional entity that has a reliability related need (Requirement R11).

The responsibilities described in Requirements R2 and R3 are explicitly assigned to the PC. The responsibilities
described in Requirements R4 through R11 may be completed by either the PC or one or more of its TPs. Requirement
R1 requires that an agreement is reached on the individual and joint responsibilities for completing the Extreme
Temperature Assessment between the PC and its TPs.

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Requirement R2
Requirement R2 requires each Planning Coordinator (PC) to identify the zone(s) it will participate in for the
components of the Extreme Temperature Assessment that require coordination. PCs in the same zone are required
to coordinate to:
•

Select one common extreme heat benchmark temperature event and one common extreme cold benchmark
temperature event (Requirement R2), and

•

Implement a process for developing benchmark planning cases and sensitivity cases (Requirement R3).

FERC Order No. 896 directed NERC to require that transmission planning studies under the new or revised Reliability
Standard consider the wide-area impacts of extreme heat and cold weather. Considering this directive, the SDT
identified the zones depicted in Attachment 1 as reasonable boundaries that balance the need for studies to cover
large regions with similar weather patterns with the need for a manageable level of coordination. An earlier proposal
to limit coordination to only adjacent PCs was not adequate for meeting FERC’s directives. While the zones depicted
in Attachment 1 will require some PCs to coordinate with many other PCs, the industry has demonstrated, through
various working groups and organizations, that it is capable of cooperating to build models that represent larger
areas. The zones depicted in Attachment 1 are either aligned with existing PC boundaries or boundaries of a group of
PCs with similar weather patterns.
Requirement R2 describes the need to select extreme benchmark temperature events necessary for the creation of
benchmark planning cases. Specifically, extreme hot and cold temperatures experienced during benchmark events
are assumed to be outside the ranges used as the basis of planning cases studied under Reliability Standard TPL-0015.1. Since temperature levels and associated weather conditions affect load levels, generation performance, and
transfer levels, the selection of benchmark events is critical to ensuring the Extreme Temperature Assessment
appropriately evaluates probable System conditions.
Since any region can experience temperatures that are higher or lower than normal, PCs within the same zone must
coordinate to select one common temperature event that includes hotter temperature assumptions and one
common temperature event that includes colder temperature assumptions. While it is understood that, for example,
one region may typically experience hotter summers and milder winters than another region, both a hotter than
average summer and a colder than average winter could result in reliability concerns. Therefore, the requirement is
for one common case specific to extreme heat and one common case specific to extreme cold conditions to be studied
for the Extreme Temperature Assessment. By selecting the same, common events, PCs ensure that extreme
temperatures are studied over the entire zone. The evaluation of a common event taking place over a wide area is
foundational to FERC Order No. 896. Furthermore, selecting the same, common events reasonably limits coordination
requirements. PCs are required to participate in the selection of events for their zone(s), but have no responsibilities
for the selection of events in other zones.
The SDT determined that the extreme heat and extreme cold temperatures selected must have a verified statistical
basis based on weather data from credible sources. The SDT has identified several key features that are used to
determine when a temperature event will constitute a valid extreme benchmark temperature event for the purposes
of completing the Extreme Temperature Assessment. Specifically, extreme benchmark temperature events must:
•

Consider no less than 40 years of temperature data,

•

Utilize data ending no more than five years prior to the time benchmark temperature events are selected,
and

•

Represent one of the worst 20 extreme temperature conditions within the zone.

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Requirement R2

Temperature events are ranked by computing the 3-day rolling average of daily maximum temperatures (for extreme
heat) or daily minimum temperatures (for extreme cold). The 3-day rolling average temperatures are calculated for
both extreme heat and extreme cold to identify multi-day periods of extreme heat or extreme cold temperature
events. The ERO will maintain a library of benchmark events to provide responsible entities access to vetted
benchmark temperature events that meet the criteria of Requirement R2. While selection of events from the ERO’s
provided library assures entities they are selecting valid events, Requirement R2 does not preclude entities from
collecting temperature data and identifying benchmark temperature events through their own process. Entities that
elect to develop their own benchmark temperature events are responsible for ensuring the input temperature data
and selected benchmark temperature events meet the criteria of Requirement R2. Additionally, because
Requirement R2 requires PCs within a zone to coordinate in the selection of the benchmark temperature events, the
process used to identify these events must be agreeable to those PCs.
The requirement to consider no less than 40 years of temperature data was established based on the observation
that many of the worst events identified in various regions of North America occurred in the 1980s and 1990s. For
example, preliminary data indicated that the five worst extreme cold temperature events in the PJM region over the
last 43 years occurred between 1983 and 1994. Similar results were seen in other regions for both extreme heat and
extreme cold temperature events. Thus, the SDT determined that a minimum of 40 years of temperature data should
be used to ensure more extreme events weren’t excluded by using a shorter duration of temperature data.

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Requirement R3
Requirement R3 aligns with directives in FERC Order No. 896, emphasizing the importance of coordinating the
development of benchmark planning cases and sensitivity cases amongst PCs within a zone, where the scope of
extreme temperature event studies will likely cover large geographical areas exceeding smaller individual planning
areas. The SDT considered comments from the industry expressing concerns regarding the necessity to coordinate
among all impacted PCs in developing benchmark planning cases and sensitivity cases for various extreme benchmark
temperature events. Recognizing that coordination among all impacted PCs may not be necessary to ensure reliability
within an individual planning area, the SDT drafted Requirement R3 to require each PC to coordinate with all PCs
within a zone to implement a process for the development of benchmark planning cases and sensitivity cases. The
SDT believes this change balances the need to ensure the planning cases capture impacts to/from entities affected
by the same benchmark temperature event, while recognizing that reliability will be less impacted by system changes
far removed from the zone.
PCs within a zone must coordinate to implement a process that results in the development of benchmark planning
cases that represent the benchmark temperature events selected in accordance with Requirement R2, and sensitivity
cases that demonstrate the impact of changes to the basic assumptions used in the benchmark planning cases. This
process requires several components, outlined in the sub-requirements of Requirement R3.
First, Requirement R3 Part 3.1 requires PCs within a zone to identify System models form the basis for developing the
benchmark planning cases. These models must represent one of the years in the Long-Term Transmission Planning
Horizon. PCs will also need to ensure models include stability modeling data to provide for the performance of
stability analysis later in the process. It is reasonably anticipated that PCs will likely utilize a summer peak model as
the starting point for the extreme heat benchmark temperature event and a winter peak model as the starting point
for the extreme cold benchmark temperature event.
Secondly, Requirement R3 Part 3.2 requires that PCs within a zone provide forecasted data for their area within the
zone that represents the benchmark temperature events selected in accordance with Requirement R2. Each PC must
provide data for their area within the zone that represents seasonal and temperature adjustments for Load,
generation, Transmission, and transfers. The provided data should be used to update the starting point models to
reflect the selected benchmark temperature events.
Thirdly, Requirement R3 Part 3.3 allows PCs to agree on assumptions for seasonal and temperature adjustments for
Load, generation, Transmission, and transfers in areas outside of the zone. As a sub-requirement of Requirement R3,
these assumptions must be coordinated among PCs in the zone, as needed. As an example, PCs within the zone may
identify the need for imported power during a benchmark event. The PCs may evaluate historical import availability
and assume an import from an area outside of the zone is reasonable and should be modeled.
Finally, Requirement R3 Part 3.4 requires PCs to coordinate and identify changes to generation, real and reactive
forecasted Load, or transfers that should be reflected in sensitivity cases. Sensitivity cases are intended to
demonstrate the impact of changes to the basic assumptions used in the benchmark planning cases, and Requirement
R3 Part 3.4 ensures PCs are cooperating to identify changes that sufficiently alter the assumptions reflected in the
benchmark planning cases. For example, PCs that identified an import external source to the zone for a benchmark
planning case may elect to alter the source of that import in the sensitivity case.

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Requirement R4
The SDT drafted Requirement R4 to require the responsible entity to use data consistent with Reliability Standard
MOD-032, supplemented by other sources as needed, for developing benchmark planning cases that represent
System conditions based on selected benchmark temperature events. This aligns with directives in FERC Order No.
896, paragraph 30, emphasizing the requirement of developing both benchmark planning cases and sensitivity study
cases. Requirement R4 is consistent with Reliability Standard TPL-001-5.1 in cross-referencing Reliability Standard
MOD-032, which establishes consistent modeling data requirements and reporting procedures for the development
of planning horizon cases necessary to support analysis of the reliability of the interconnected System. It is also
consistent with Reliability Standard TPL-001-5.1 in acknowledging that data from other sources may be required to
supplement the data collected through Reliability Standard MOD-032 procedures.
FERC Order No. 896, paragraph 116, directs NERC “to require in the new or modified Reliability Standard that
responsible entities model demand load response in their extreme weather event planning area”. This requirement
can be met via the use of data consistent with Reliability Standard MO-032, as included in the TPL-008-1 standard’s
Requirement R4. The modeling of the demand load response can be implemented through the use of MOD-032 in
which data needed for study base case development can be requested and obtained for development of the
benchmark planning cases and sensitivity cases.
Requirement R4 requires entities to use the coordination process developed in accordance with Requirement R3 to
develop the following four cases:
•

One common extreme heat benchmark planning case (Requirement R4 Part 4.1),

•

One common extreme cold benchmark planning case (Requirement R4 Part 4.1),

•

One common extreme heat sensitivity case (Requirement R4 Part 4.2), and

•

One common extreme cold sensitivity case (Requirement R4 Part 4.2).

At the completion of the case development process, implemented in accordance with Requirement R3, and executed
in Requirement R4, responsible entities will have the four cases listed above. This establishes category P0 as the
normal System condition in Table 1 for each case. Requirement R3 does not preclude PCs from implementing a
process that develops cases for multiple benchmark temperature events or additional sensitivity cases. Moreover,
entities may elect to develop additional cases for their internal use.
As per FERC Order No. 896, paragraph 94, it is clarified that resource adequacy benchmarks are not within the scope
of TPL-008-1. The intent of the standard is to evaluate benchmark events where sufficient generation is available to
supply load. However, under an extreme heat or extreme cold temperature condition, there may be instances where
the benchmark planning cases and/or sensitivity cases may not have sufficient available generation to supply the
load. In these scenarios, it may be acceptable for the responsible entity to revise the model to reduce the forecasted
Load, or include forecasted generation, to achieve a solution for the benchmark planning cases and/or sensitivity
cases and evaluate future Bulk Electric System performance for extreme temperature events. Each responsible entity,
as identified in Requirement R1, shall have dated evidence in either electronic or hard copy format that it developed
benchmark planning cases and sensitivity cases in accordance with Requirement R4.

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Requirement R5
Requirement R5 was drafted to require each responsible entity to set the criteria needed for limits that will be used
to evaluate System steady state voltage and post-Contingency voltage deviations for completing the Extreme
Temperature Assessment. The establishment of these criteria allows auditors to compare the results of the Extreme
Temperature Assessment with the established criteria.

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Requirement R6
Requirement R6 was drafted to require the responsible entity to define and document the criteria or methodology
used in evaluating the Extreme Temperature Assessment analysis to identify instability, uncontrolled separation, or
Cascading within an Interconnection. In developing planning benchmark as well as sensitivity cases for steady-state
and transient stability analyses, the Planning Coordinators and Transmission Planners typically use Interconnectionwide starting cases prior to further modifications to reflect the conditions of the benchmark events as well as
modifications for sensitivity cases. Analyses that may result in instability, uncontrolled separation, or Cascading
typically are confined within an Interconnection where generation and transmission Facilities are interconnected. It
is not expected that instability, uncontrolled separation, or Cascading that affect Facilities within an Interconnection
would impact other Interconnection(s) as these systems are asynchronous systems (i.e., not connecting
synchronously). Adequate and thorough criteria should be built into the Extreme Temperature Assessment to help
identify instability, uncontrolled separation, and Cascading conditions. The establishment of these criteria allows
auditors to compare the results of the Extreme Temperature Assessment with the established criteria.

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Requirement R7
This requirement addresses directives in FERC Order No. 896 to define a set of Contingencies that responsible entities
will be required to consider when conducting wide-area studies of extreme heat and cold weather events. FERC’s
preference to rely on established Contingency definitions, “[w]e believe that it is necessary to establish a set of
common contingencies for all responsible entities to analyze. Required contingencies, such as those listed in Table 1
of Reliability Standard TPL-001-5.1 (i.e., category P1 through P7), establish common planning events that set the
starting point for transmission system planning assessments,” was also considered by the SDT. It is necessary to
establish a set of common Contingencies for all responsible entities to analyze. Requiring the study of predefined
Contingencies, such as those listed in Table 1, will ensure a level of uniformity across planning regions, considering
that extreme heat and cold weather events often exceed the geographic boundaries of most existing planning
footprints. Defining the Contingencies in Table 1 consistently with Table 1 of Reliability Standard TPL-001-5.1 meets
FERC’s preference for commonality.
If feasible, all Contingencies listed in Table 1 should be considered for evaluation by the responsible entity; however,
the language affords flexibility in identifying the most appropriate Contingencies. As such, the responsible entity
should implement a method and establish sufficient supporting rationale to ensure Contingencies within each
category of Table 1, that are expected to produce more severe System impacts within its planning area, are
adequately identified. It is noted that since the benchmark planning cases are developed from the extreme
temperature benchmark events, they already represent extreme System conditions and thus not all Contingencies
from Reliability Standard TPL-001-5.1 Table 1 are included in the TPL-008-1 Table 1 for assessment. The Events
included in TPL-008-1 Table 1 represent the more likely Contingencies to occur.
The SDT included categories P0, P1, and P7 in Table 1 of TPL-008-1. The SDT finds it reasonable to exclude P2, P3, P4,
P5 and P6 Contingencies from the Extreme Temperature Assessment. Studying categories P0, P1 and P7 is the
minimum requirement of TPL-008-1. The standard does not preclude entities from studying additional Contingencies
if desired. The following discusses the rationale for excluding P2 through P6 Contingencies for TPL-008-1:
1. Excluding P2 and P4 Contingencies:
After consideration of comments received from the industry, the SDT removed P2 and P4 Contingencies due
to lower probability of occurrence than P1 and P7 Contingencies. TPL-008 now focuses on the single
Contingencies (P1) or multiple Contingencies on common structure (P7) that are more likely to be monitored
in operational scenarios. P2 Contingencies (e.g. Contingencies caused by internal breaker fault, bus section
fault, opening line section without a fault), and P4 Contingencies (e.g., Contingencies caused by stuck
breaker), while plausible under extreme temperature conditions, occur in much less frequency when
compared to P1 and P7 Contingencies. The standard establishes minimum requirement for Contingencies
with higher probability of occurrence. To the extent that the responsible entity determines the need for
studying beyond the minimum requirements, the standard does not preclude the entity from doing so.
2. Excluding P3 and P6 Contingencies:
Part of the decision stems from the complexity of P3 and P6 Contingencies, which involve multiple element
outages triggered by multiple Contingencies, with System adjustments allowed between them.
Consequently, the occurrence likelihood of P3 and P6 Contingencies could be even lower compared to P1
and P7 Contingencies. Moreover, aligning with the directives set forth in FERC Order 896, which emphasizes
the importance of incorporating derated generation, transmission capacity, and the availability of generation
and transmission in the development of benchmark planning cases, it becomes imperative for responsible
entities to consider potential concurrent or correlated generation and transmission outages and/or derates
within relevant benchmark planning cases. This ensures that the benchmark planning case accurately reflects
System conditions under extreme temperatures, with generation and transmission derates and/or outages

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Requirement 7

already factored. Therefore, the SDT believes excluding P3 and P6 is justified, as generation and transmission
derates and/or outages are already accounted for within the benchmark planning cases.
3. Excluding P5 Contingencies:
After consideration of comments received from the industry, the SDT removed P5 Contingency (Delayed Fault
Clearing due to failure of non-redundant component of a Protection System). This is because while some
categories of Contingencies may be assessed in a straightforward approach, category P5 Contingency events
often require a significant level of engineering analysis (including protection and/or control analysis). These
analyses are sensitive to the System topology and expected dispatch. As the planning benchmark cases are
developed for TPL-008-1 that represent System conditions that are different than the typical summer or
winter peak conditions, the development of category P5 Contingency events is expected to be a significant
burden. Since these events only require evaluations of possible mitigations (and not Corrective Action Plans),
violations resulting from these events are unlikely to result in significant transmission System investment.
Furthermore, any violations resulting from category P5 events may be mitigated by eliminating and
addressing the single point of failure included in the event definition. Thus, the evaluation of possible actions
is unlikely to result in further insight beyond the general reliability improvements associated with eliminating
single points of failure.
The SDT discussed and decided to keep the P7 Contingency category because common structure Contingencies are
often evaluated after categories P0 and P1 as the most common minimum level of transmission reliability assessment.
These events have a high likelihood of occurrence due to the following reasons:
•

Historical events that include simultaneous forced outage due to tripping of the double-circuit power lines
due to electrical storm events;

•

Environment-caused factors include pollution buildup, such as dust, that could cause faulted condition that
trips both transmission lines on a common tower;

•

Avian-caused outages that impact both transmission lines on a common tower;

•

Smoke from nearby wildfires can cause simultaneous tripping of both circuits on a common tower;

•

Nearby wildfires can impact System Operation as System Operators proactively de-energize both lines on a
common tower to avoid further impact to the transmission grid in the event of a simultaneous tripping of
both lines that may be carrying high power transfer between areas;

•

Weather-related causes such as lightning, flooding, wind, or icing can cause tripping of both transmission
lines on a common tower;

•

Natural disaster such as winter storm can cause transmission tower to collapse, taking out both lines strung
on the same tower;

•

Other incidents such as vehicle accident, aircraft accident, vandalism, or animal contact that can adversely
impact both transmission lines on the common tower.

Loss of two circuits running in parallel, simultaneously, is likely to have a greater system impact versus loss of two
unrelated or geographically separated circuits. Therefore, there is greater potential for reliability concerns,
especially during heavy transfers that are likely during periods of extreme weather, due to loss of both circuits of a
double-circuit line. Due to the reasons above, Contingencies that involve double-line circuits on a common tower
are included in the critical multiple Contingency list in either transmission planning or System Operations reliability
assessment.
Some, but not all, items to consider when developing the rationale for selecting Contingencies are:
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•

Past studies,

•

Subject matter expert knowledge of the responsible entity’s System (to be supplemented with data or
analysis), and

•

Historical data from past operating events.

Lastly, regarding the Bulk Electric System (BES) voltage levels for the Contingencies, the SDT reviewed previous major
wide-area benchmark events and found that the Facilities that were out of service by these events have voltages that
are 200 kV and above. Thus, it is the reason for establishing voltages of 200 kV and above for Contingencies in Table
1 of TPL-008-1. The monitoring of potential impact is still applicable to Facilities with all BES voltage levels. However,
with that said, the SDT recognized that many PCs and TPs have Contingencies that include all BES levels. Responsible
entities may elect to use the existing Contingencies that they already have and report the criteria violations for the
categories in TPL-008-1 Table 1.

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Requirement R8
Requirement R8 was drafted to provide clarity on the following:
1. What planning study cases are required?
The Requirement R8 includes the following number of assessments to complete the Extreme Temperature
Assessment and address FERC Order No. 896 directives per paragraph 111 that “direct NERC to require in
the proposed new or modified Reliability Standard that responsible entities perform both steady state and
transient stability (dynamic) analyses in the extreme heat and cold weather planning studies”. In addition,
Requirement R8 also addresses FERC Order No. 896 directives per paragraph 124 that “require the use of
sensitivity cases to demonstrate the impact of changes to the assumptions used in the benchmark planning
case”. Requirement R8 also addresses FERC Order No. 896 directives per paragraph 124 that sensitivity
cases “should consider including conditions that vary with temperature such as load, generation, and
system transfers.” Since the benchmark planning case(s) already include System conditions under extreme
heat or extreme cold events, the sensitivity analysis is to include changes to at least one of the following
conditions: generation, real and reactive forecasted Load, or transfers. Since the minimum requirement
includes changes to one of these conditions, the PCs and the TPs can include further sensitivity assessments
to change more conditions if they choose to do so.
The following provides the number of assessments required for the benchmark planning and sensitivity
cases to complete the Extreme Temperature Assessment.
Type of Extreme
Temperature
Assessment

Extreme Cold Temperature
Event

Extreme Heat
Temperature Event

Total

Benchmark Planning
Case Analysis

One extreme cold
benchmark planning case
assessment

One extreme heat
benchmark planning case
assessment

Two benchmark
planning case
assessments

Sensitivity Case
Analysis

One sensitivity case with
changes to at least one of
the following conditions:
generation, real and
reactive forecasted Load,
or transfers

One sensitivity case with
changes to at least one of
the following conditions:
generation, real and
reactive forecasted Load,
or transfers

Two sensitivity case
assessments

Total

A total of four
assessments to
complete the
Extreme
Temperature
Assessment

2. What are the types of analyses required?
There are two types of analyses required: steady-state and transient stability. Each type of analysis must be
completed for each of the four cases described in the table above. This requirement is to satisfy FERC Order
No. 896 directive paragraph 111.

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Requirement R9
FERC Order No. 896 identifies a deficiency in the existing Reliability Standard TPL-001-5.1 where “planning
coordinators and transmission planners are required to evaluate possible actions to reduce the likelihood or mitigate
the consequences of extreme temperature events but are not obligated to develop corrective action plans” (¶139).
Given potential severe consequences of extreme cold and extreme heat events, FERC Order No. 896 raises the bar
and “directs NERC to require in the new or modified Reliability Standard the development of extreme weather
corrective action plans for specified instances when performance standards are not met” (¶152).
Due to higher likelihood of categories P0 and P1, these categories are held to a higher performance requirement in
benchmark planning cases. Corrective Action Plans are required to address performance deficiencies for categories
P0 and P1 in benchmark planning cases analyzed in the Extreme Temperature Assessment.
Furthermore, having a Corrective Action Plan requirement for categories P0 and P1 in benchmark planning cases
ensures resilience during future extreme cold and extreme heat temperature events, when the transmission System
is required to be P1 Contingency-secure (for steady-state and transient stability).
Given that a category P0 represents a continuous System condition without any system disturbances, the SDT
determined that load shedding should not be considered as a Corrective Action Plan. However, the SDT has
determined that load curtailment may be considered for a P1 Contingency as a Corrective Action Plan where load
shed is allowed to prevent system-wide failures and ensuring the continued operation of essential services under a
critical P1 Contingency in the extreme heat and cold temperature events. The SDT also emphasizes that alternative
solutions, other than firm load curtailment, are evaluated in higher priorities. Non-Consequential Load Loss is
permitted as an interim solution in situations that are beyond the control of the Planning Coordinator or Transmission
Planner that prevent the implementation of a Corrective Action Plan in the required timeframe; however, the
responsible entity must document the situation causing the problem, alternatives evaluated, and take actions to
resolve the situation. Future revisions to the Corrective Action Plan are allowed, provided that the planned Bulk
Electric System continues to meet the performance requirements of Table 1.
FERC Order No. 896 also directs NERC “to develop certain processes to facilitate interaction and coordination with
applicable regulatory authorities or governing bodies responsible for retail electric service as appropriate in
implementing a corrective action plan” (¶152). In the event that Non-Consequential Load Loss is included in the
Corrective Action Plan for a P1 Contingency, the responsible entity shall document alternative(s) considered, make
the Corrective Action Plan available to, and solicit feedback from, applicable regulatory authorities or governing
bodies responsible for retail electric service issues.
Lastly, the standard also permits the responsible entities to revise or update the Corrective Action Plan that was
considered and approved in the previous Extreme Temperature Assessment. This allows responsible entities to
incorporate approved mitigation measures from other planning assessments, such as annual transmission reliability
assessment under TPL-001-5 or subsequent related planning standard, or from other planning assessments for policydriven or economic needs. The revised or updated Corrective Action Plan associated with TPL-008-1 can be
documented as an addendum to the previous Extreme Temperature Assessment’s Corrective Action Plan.

NERC | Technical Rationale and Justification for TPL-008-1 | December 2024
18

Requirement R10
The requirement for responsible entities to evaluate and document possible actions designed to reduce the likelihood
or mitigate the consequences and adverse impacts when the study results in the benchmark planning cases analyses
conclude there could be instability, uncontrolled separation, or Cascading for P7 Contingencies is in response to
directives outlined in FERC Order No. 896.
P7 Contingencies involve multiple element outages resulting from a single event, making them relatively less likely to
occur, compared to categories P0 and P1, but potentially causing more severe system impacts. Considering both the
likelihood of these Contingencies, and the fact that the Extreme Temperature Assessment already addresses lowprobability System conditions, the SDT determined that Corrective Action Plans should not be required for P7
Contingencies. However, due to the potential severity resulting from single-Contingency multiple element outages,
the SDT believes it is appropriate for responsible entities to at least evaluate and document possible mitigation
actions to reduce the likelihood or mitigate the consequences and adverse impacts of the event(s) when analyses
conclude there could be instability, uncontrolled separation, or Cascading. The biggest benefit from the evaluation
and documentation of the possible mitigating actions is it allows a responsible entity to see where major reliability
concerns exist that may need to be addressed; and, if a sufficiently large number of reliability concerns are identified,
it may encourage transmission upgrade mitigation option(s) to be considered and implemented without it being
strictly called for in the standard. Not requiring Corrective Action Plans for these Contingencies, but requiring the
evaluation, is a compromise from having Corrective Action Plans for all studied Contingencies.
Furthermore, FERC Order No. 896 requires “the use of sensitivity cases to demonstrate the impact of changes to the
assumptions used in the benchmark planning case” (¶124). FERC Order No. 896 also states: “NERC should determine
whether corrective action plans should be required for single or multiple sensitivity cases, and whether corrective
action plans should be developed if a contingency event that is not already included in benchmark planning case
would result in cascading outages, uncontrolled separation, or instability” (¶158). The SDT acknowledges that
sensitivity analysis is an important component of a robust transmission planning study. A requirement to develop
and implement Corrective Action Plans for sensitivity cases may incentivize responsible entities to select fewer or
less severe sensitivities. An incentive to select fewer sensitivities is undesirable because sensitivity study results are
used to identify constraints and initiate deeper analysis into the variables that impact those constraints. The study
results of sensitivity cases are also important to inform the development of Corrective Action Plans in the benchmark
planning cases. Therefore, the SDT determined the responsible entity must evaluate and document possible actions
designed to reduce the likelihood or mitigate the consequences and adverse impacts of the event(s) when analyses
of sensitivity cases conclude there could be instability, uncontrolled separation, or Cascading for categories P0, P1,
and P7. Finally, TPL-008-1 does not preclude the responsible entity from developing Corrective Action Plans for
sensitivity cases beyond what is required in the standard.

NERC | Technical Rationale and Justification for TPL-008-1 | December 2024
19

Requirement R11
The requirement for responsible entities to share Extreme Temperature Assessment results aligns with directives in
FERC Order No. 896, emphasizing coordination and sharing of study findings. It ensures collaboration among
stakeholders and timely dissemination of critical information to entities with reliability-related needs. This fosters a
collective understanding of reliability concerns identified in wide-area studies, thereby enhancing overall grid
reliability.

NERC | Technical Rationale and Justification for TPL-008-1 | December 2024
20

Attachment 1: Extreme Temperature Assessment Zones
The map depicts an approximation of the zones to be used in the Extreme Temperature Assessment and is provided
as a visual aid for each Planning Coordinator to identify the zone(s) to which the Planning Coordinator belongs to
under Attachment 1. The zone topology is a function of balancing authority jurisdiction and general knowledge of
zonal weather patterns, or in some cases, are limited by transmission constraints, or lack of transmission thereof,
between zones. The goal of the topology was to split the North American System into several distinct zones that have
similar electric power system properties (i.e., balancing authority and interconnections) and similar weather or
climatological patterns. Balancing authorities with large areas of jurisdiction, exclusively ISOs and RTOs, are assigned
their own weather zone. In geographical areas comprised of multiple balancing authorities, generalized weather
zones are created to best represent zonal weather patterns.
The NPCC region of the Eastern Interconnection was divided into New England, New York, Quebec Interconnection,
Ontario, and Maritimes. The Planning Coordinators for the NPCC region of the Eastern Interconnection are listed
below:
•

New England: Planning Coordinators in NPCC that primarily serve the six New England States.

•

New York: Planning Coordinators in NPCC that primarily serve New York.

•

Quebec: Planning Coordinators that primarily serve Quebec in the NPCC Region.

•

Ontario: Planning Coordinators in NPCC that primarily serve Ontario.

•

Maritimes: Planning Coordinators in NPCC that primarily serve New Brunswick, Nova Scotia, Prince Edward
Island, and the Northern Maine Independent System Administrator (NMISA). The NMISA is responsible for
the administration of the northern Maine transmission system and electric power markets in Aroostook and
Washington counties, with the load served radially from New Brunswick. It was not included in the New
England division since there are no physical transmission ties between NMISA and ISO-NE which is the
Planning Coordinator serving the remainder of the six New England States.

Additionally, SERC combined NERC Assessment areas of SERC-East, SERC-Central, and SERC-Southeast into a single
zone based on climate similarities. Northwest Regions, WECC-SW, SERC, and SERC-FP were based on balancing
authority PNNL data. SPP-N, SPP-S, MISO-N, and MISO-S were aggregated based on county-level PNNL data.

NERC | Technical Rationale and Justification for TPL-008-1 | December 2024
21

Violation Risk Factor and Violation Severity Level
Justifications

Project 2023-07 Transmission System Planning Performance Requirements for
Extreme Weather
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 2023-07 Transmission System Planning Performance Requirements for Extreme Weather. 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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

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
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.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

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 Justifications for TPL-008-1, Requirement R1
Proposed VRF

Lower

NERC VRF Discussion

A VRF of Lower is appropriate due to the fact that the Planning Coordinators, in conjunction with its
Transmission Planner(s) will determine joint responsibilities for requirements throughout TPL-008-1.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

5

VSLs for TPL-008-1, Requirement R1
Lower

Moderate

High

Severe

The responsible entity completed
its individual and joint
responsibilities such that the
Extreme Temperature Assessment
was completed, but it was
completed less than or equal to six
months late.

The responsible entity completed
its individual and joint
responsibilities such that the
Extreme Temperature Assessment
was completed, but it was
completed more than six months
but less than or equal to 12 months
late.

The responsible entity completed
its individual and joint
responsibilities such that the
Extreme Temperature Assessment
was completed, but it was
completed more than 12 months
but less than or equal to 18 months
late.

The Planning Coordinator, in
conjunction with its Transmission
Planner(s), failed to identify
individual and joint responsibilities
for completing the Extreme
Temperature Assessment.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

OR
The responsible entity completed
its individual and joint
responsibilities such that the
Extreme Temperature Assessment
was completed, but it was
completed more than 18 months
late.

6

VSL Justifications for TPL-008-1, Requirement R1
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the Planning Coordinator and Transmission Planner to determine
who completes the responsibilities throughout TPL-008-1. The responsibilities documentation will either be
developed or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

7

VRF Justifications for TPL-008-1, Requirement R2
Proposed VRF

High

NERC VRF Discussion

A VRF of high is appropriate due to the fact that selecting a benchmark event to perform an extreme
temperature assessment can affect the grid based on planning analysis for future events.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

8

VSLs for TPL-008-1, Requirement R2
Lower
N/A

Moderate
N/A

High

Severe

The Planning Coordinator
coordinated with all Planning
Coordinators within each identified
zone to identify one common
extreme heat and one common
extreme cold benchmark
temperature event for completing
the Extreme Temperature
Assessment, but one of the
identified events failed to meet all
the criteria of Requirement R2.

The Planning Coordinator
coordinated with all Planning
Coordinators within each identified
zone to identify one common
extreme heat and one common
extreme cold benchmark
temperature event for completing
the Extreme Temperature
Assessment, but both of the
identified events failed to meet all
of the criteria of Requirement R2.
OR
The Planning Coordinator failed to
coordinate with all Planning
Coordinators within each identified
zone to identify one common
extreme heat and one common
extreme cold benchmark
temperature event for completing
the Extreme Temperature
Assessment.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

9

VSL Justifications for TPL-008-1, Requirement R2
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

This VSL has been assigned as a binary due to the benchmark event needing to be selected for benchmark
planning cases to be completed. You either select a benchmark event or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

10

VRF Justifications for TPL-008-1, Requirement R3
Proposed VRF

Medium

NERC VRF Discussion

A VRF of medium is appropriate due to the fact that it is important to develop and maintain System models
within an entity’s planning area for performing Extreme Temperature Assessments. Connecting to MOD-032 to
provide important data needed to assist entities with System models is also important for accurate information
to be used.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

11

VSLs for TPL-008-1, Requirement R3
Lower
N/A

Moderate
N/A

High
N/A

Severe
The Planning Coordinator did not
coordinate with all Planning
Coordinators within each of its
identified zone(s) to implement a
process for developing benchmark
planning cases.
OR
The Planning Coordinator
coordinated with all Planning
Coordinators within each of its
identified zone(s) to implement a
process for developing benchmark
planning cases, but the process did
not include all of the required
elements.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

12

VSL Justifications for TPL-008-1, Requirement R3
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either develops and maintains the System
models within its planning area or it does not develop and maintain the System models within its planning area.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

13

VRF Justifications for TPL-008-1, Requirement R4
Proposed VRF

High

NERC VRF Discussion

The VRF of High is appropriate because it could directly affect the electrical state or capability of the BPS if
coordination is not completed for benchmark planning cases and sensitivity cases for the Extreme Temperature
Assessment results.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

14

VSLs for TPL-008-1, Requirement R4
Lower
N/A

Moderate
N/A

High
N/A

Severe
The responsible entity, as identified
in Requirement R1, did not use the
process developed in Requirement
R3 to develop benchmark planning
cases or sensitivity cases.
OR
The responsible entity, as identified
in Requirement R1, used the
process developed in Requirement
R3 to develop benchmark planning
cases and sensitivity cases, but did
not use data consistent with that
provided in accordance with the
MOD-032 standard, supplemented
by other sources as needed, for
one or more of the required cases.
OR
The responsible entity, as identified
in Requirement R1, used the
process developed in Requirement
R3 and data consistent with that
provided in accordance with the
MOD-032 standard, supplemented
as needed, but failed to develop
one or more of the required
planning or sensitivity cases.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

15

VSL Justifications for TPL-008-1, Requirement R4
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the Planning Coordinator to develop and implement a process for
coordinating the development of benchmark planning cases. The benchmark planning cases will either be
developed and implemented or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

16

VRF Justifications for TPL-008-1, Requirement R5
Proposed VRF

Medium

NERC VRF Discussion

A VRF of medium is appropriate due to the importance of having criteria for acceptable System steady state
voltage limits of post-Contingency voltage deviations for performing Extreme Temperature Assessments.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

17

VSLs for TPL-008-1, Requirement R5
Lower
N/A

Moderate
N/A

High
N/A

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

Severe
The responsible entity, as identified
in Requirement R1, did not have
criteria for acceptable System
steady state voltage limits and
post-Contingency voltage
deviations for completing the
Extreme Temperature Assessment.

18

VSL Justifications for TPL-008-1, Requirement R5
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either having acceptable criteria for System
steady state voltage limits and post-contingency voltage deviations or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

19

VRF Justifications for TPL-008-1, Requirement R6
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate due to the importance of defining and documenting the criteria or methodology for
System instability, uncontrolled separation, or Cascading.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

20

VSLs for TPL-008-1, Requirement R6
Lower
N/A

Moderate
N/A

High
N/A

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

Severe
The responsible entity, as identified
in Requirement R1, failed to define
or document the criteria or
methodology to be used in the
Extreme Temperature Assessment
to identify instability, uncontrolled
separation, or Cascading within an
Interconnection.

21

VSL Justifications for TPL-008-1, Requirement R6
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

22

VRF Justifications for TPL-008-1, Requirement R7
Proposed VRF

Medium

NERC VRF Discussion

A VRF of medium is appropriate for this requirement. Identifying Contingencies for performing Extreme
Temperature Assessments for each of the event categories in Table 1 can indirectly impact the BES.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

23

VSLs for TPL-008-1, Requirement R7
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity, as identified
in Requirement R1, identified
Contingencies for each category in
Table 1 that are expected to
produce more severe System
impacts on its portion of the Bulk
Electric System, but did not include
the rationale for those
Contingencies selected for
evaluation as supporting
information.

The responsible entity, as identified
in Requirement R1, did not identify
Contingencies for each category in
Table 1 that are expected to
produce more severe System
impacts on its portion of the Bulk
Electric System.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

24

VSL Justifications for TPL-008-1, Requirement R7
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

25

VRF Justifications for TPL-008-1, Requirement R8
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate due to the importance of performing an Extreme Temperature Assessment every 5
years.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

26

VSLs for TPL-008-1, Requirement R8
Lower

Moderate

High

Severe

The responsible entity, as identified
in Requirement R1, completed
steady state and transient stability
analyses in the Extreme
Temperature Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for one
or more sensitivity cases in
accordance with Requirement R8.

The responsible entity, as identified
in Requirement R1, completed
steady state and transient stability
analyses in the Extreme
Temperature Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for one
or more benchmark planning cases
in accordance with Requirement
R8.

The responsible entity, as identified
in Requirement R1, completed
steady state and transient stability
analyses in the Extreme
Temperature Assessment using the
Contingencies identified in
Requirement R7, but failed to
document results for one or more
of the sensitivity cases in
accordance with Requirement R8.

The responsible entity, as identified
in Requirement R1, completed
steady state and transient stability
analyses in the Extreme
Temperature Assessment using the
Contingencies identified in
Requirement R7, but failed to
document results for one or more
of the benchmark planning cases in
accordance with Requirement R8.
OR
The responsible entity, as identified
in Requirement R1, failed to
complete steady state or transient
stability analyses and document
results in the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, in accordance
with Requirement R8.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

27

VSL Justifications for TPL-008-1, Requirement R8
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

28

VRF Justifications for TPL-008-1, Requirement R9
Proposed VRF

High

NERC VRF Discussion

A VRF of High is appropriate for this requirement. Developing a Corrective Action Plan is important to the BES as
it assists entities when Systems are unable to meet performance requirements.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

29

VSLs for TPL-008-1, Requirement R9
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity, as identified
in Requirement R1, developed a
Corrective Action Plan in
accordance with Requirement R9,
but failed to make its Corrective
Action Plan available to, or solicit
feedback from, applicable
regulatory authorities or governing
bodies responsible for retail
electric service issues.

The responsible entity, as identified
in Requirement R1, failed to
develop a Corrective Action Plan
when the benchmark planning case
study results indicate the System is
unable to meet performance
requirements for the Table 1 P0 or
P1 Contingencies.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

OR
The responsible entity, as identified
in Requirement R1, developed a
Corrective Action Plan, but it was
missing one or more of the
elements of Requirement R9 Part
9.1, 9.3 and 9.4 (as applicable).

30

VSL Justifications for TPL-008-1, Requirement R9
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the responsible entity either having acceptable criteria for System
steady state voltage limits and post-contingency voltage deviations or not.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

31

VRF Justifications for TPL-008-1, Requirement R10
Proposed VRF

Lower

NERC VRF Discussion

A VRF of lower has been assigned to Requirement R10. Documenting possible actions to reduce the likelihood
or mitigate the consequences and adverse impacts are administrative in nature.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

32

VSLs for TPL-008-1, Requirement R10
Lower
N/A

Moderate
N/A

High

Severe

The responsible entity, as identified
in Requirement R1, evaluated and
documented possible actions to
reduce the likelihood or mitigate
the consequences and adverse
impacts of the event(s) when
analyses conclude there could be
instability, uncontrolled separation,
or Cascading within an
Interconnection where required
under Requirement R10 Part 10.1,
but failed to evaluate and
document possible actions where
required under Requirement R10
Part 10.2.

The responsible entity, as identified
in Requirement R1, evaluated and
documented possible actions to
reduce the likelihood or mitigate
the consequences and adverse
impacts of the event(s) when
analyses conclude there could be
instability, uncontrolled separation,
or Cascading within an
Interconnection where required
under Requirement R10 Part 10.2,
but failed to evaluate and
document possible actions where
required under Requirement R10
Part 10.1.
OR
The responsible entity, as identified
in Requirement R1, failed to
evaluate and document possible
actions to reduce the likelihood or
mitigate the consequences and
adverse impacts of the event(s)
when analyses conclude there
could be instability, uncontrolled
separation, or Cascading within an
Interconnection where required
under Requirement R10 Parts 10.1
and 10.2.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

33

VSL Justifications for TPL-008-1, Requirement R10
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The VSL has been assigned as a binary due to the fact that the responsible entity will have evaluated and
documented possible actions to mitigate adverse impacts.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

34

VRF Justifications for TPL-008-1, Requirement R11
Proposed VRF

Medium

NERC VRF Discussion

The VRF of Medium is appropriate because it could directly affect the electrical state or capability of the BES if
entities are not aware of the results from its Extreme Temperature Assessment results.

FERC VRF G1 Discussion
Guideline 1- Consistency with
Blackout Report

This VRF is in line with the identified areas from the FERC list of critical areas in the Final Blackout Report.

FERC VRF G2 Discussion
Guideline 2- Consistency within a
Reliability Standard

This requirement has only a main VRF and no different sub-requirement VRFs.

FERC VRF G3 Discussion
Guideline 3- Consistency among
Reliability Standards

This VRF is in line with other VRFs that address similar reliability goals in different Reliability Standards.

FERC VRF G4 Discussion
Guideline 4- Consistency with NERC
Definitions of VRFs

The assigned VRF is consistent with NERC definition of VRFs.

FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Co-mingle More
than One Obligation

This requirement does not mingle a higher risk reliability objective and a lesser risk reliability objective.
Therefore, the VRF reflects the risk of the whole requirement.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

35

VSLs for TPL-008-1, Requirement R11
Lower

Moderate

High

Severe

The responsible entity, as identified
in Requirement R1, provided its
Extreme Temperature Assessment
results to functional entities having
a reliability related need who
requested the information in
writing, but it was more than 60
days but less than or equal to 80
days following the request.

The responsible entity, as identified
in Requirement R1, provided its
Extreme Temperature Assessment
results to functional entities having
a reliability related need who
requested the information in
writing, but it was more than 80
days but less than or equal to 100
days following the request.

The responsible entity, as identified
in Requirement R1, provided its
Extreme Temperature Assessment
results to functional entities having
a reliability related need who
requested the information in
writing, but it was more than 100
days but less than or equal to 120
days following the request.

The responsible entity, as identified
in Requirement R1, provided its
Extreme Temperature Assessment
results to functional entities having
a reliability related need who
requested the information in
writing, but it was more than 120
days following the request.
OR
The responsible entity, as identified
in Requirement R1, did not provide
its Extreme Temperature
Assessment results to functional
entities having a reliability related
need who submitted a written
request for the information.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

36

VSL Justifications for TPL-008-1, Requirement R11
FERC VSL G1
Violation Severity Level Assignments
Should Not Have the Unintended
Consequence of Lowering the
Current Level of Compliance

The requirement is new. Therefore, the proposed VSL do not have the unintended consequence of lowering the
level of compliance.

FERC VSL G2
Violation Severity Level Assignments
Should Ensure Uniformity and
Consistency in the Determination of
Penalties

The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.

Guideline 2a: The Single Violation
Severity Level Assignment Category
for "Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level Assignment
Should Be Consistent with the
Corresponding Requirement

The proposed VSL use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.

FERC VSL G4
Violation Severity Level Assignment
Should Be Based on A Single
Violation, Not on A Cumulative
Number of Violations

Each VSL is based on a single violation and not cumulative violations.

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
VRF and VSL Justifications | December 2024

37

Consideration of FERC Order 896 Directives

Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather
December 2024
On June 15, 2023, FERC issued a Final Rule, Order No. 896, directing NERC to develop a new or modified Reliability Standard to address a lack
of a long-term planning requirement(s) for extreme heat and cold weather events. Specifically, FERC directed NERC to develop modifications to
Reliability Standard TPL-001-5.1 or to develop a new Reliability Standard to require the following: (1) development of benchmark planning
cases based on major prior extreme heat and cold weather events and/or meteorological projections; (2) planning for extreme heat and cold
weather events using steady state and transient stability analyses expanded to cover a range of extreme weather scenarios including the
expected resource mix's availability during extreme heat and cold weather conditions, and including the wide-area impacts of extreme heat
and cold weather; and (3) development of corrective action plans that mitigate any instances where performance requirements for extreme
heat and cold weather events are not met. FERC directed NERC to submit a new or revised standard within 18 months, or by December 2024.
The below provides the directives from FERC Order 896 along with the drafting team’s consideration of the directives.

Directive Language

FERC Order 896 Directives

P35. “[W]e direct NERC to: (1) develop extreme heat and cold weather
benchmark events, and (2) require the development of benchmark
planning cases based on identified benchmark events.”
P36: “…As recommended by commenters, NERC should consider the
examples of approaches for defining benchmark events identified in the
NOPR (e.g., the use of projected frequency or probability distribution).
NERC may also consider other approaches that achieve the objectives
outlined in this final rule.”

Consideration of Directives

The ERO has worked with respective subject matter experts, including
climate experts, the six regions, etc., to explore extreme heat and extreme
cold benchmark temperature events. NERC, in consultation with climate
data subject matter expert consultants on the benchmark events, utilized
publicly available modeled data to address the requirements of TPL-008-1
that define extreme heat and extreme cold benchmark temperature
events.
Specifically, based on the available data, the drafting team determined that
extreme benchmark temperature events must: 1) consider no less than
forty years of historical temperature data, 2) include recent temperature

RELIABILITY | RESILIENCE | SECURITY

Directive Language

FERC Order 896 Directives

Consideration of Directives

data due to ongoing climate changes, and 3) represent one of the twenty
worst extreme temperature conditions over the forty year period, based on
a 3-day rolling average of daily maximum (heat) or minimum (cold)
temperatures.
The ERO will maintain a library of benchmark temperature events that
meet these requirements. Responsible entities will be able to review and
select benchmark temperature events from this library to assist with the
development of benchmark planning cases. However, responsible entities
may also identify benchmark temperature events via their own processes,
provided that the event meets the criteria of Requirement R2 and is agreed
upon by all PCs within the zone.
Should the extreme heat and cold weather benchmark events provided not
suffice for the entities zone, the Planning Coordinator (PC) in coordination
with all PCs within its zone, may develop a common extreme heat and
extreme cold weather benchmark event to use for the TPL-008-1 Standard.
The drafting team developed requirements within TPL-008-1 to require PCs
within zones to select one common extreme heat benchmark temperature
event and one common extreme cold benchmark temperature event
(Requirement R2). After selecting its benchmark events, the responsible
entity is required to implement a process for coordinating the development
of benchmark planning cases and sensitivity cases among the responsible
entities (Requirement R3) and to develop benchmark planning cases and
sensitivity cases (Requirement R4).

Consideration of FERC Order 896 Directives
Project 2023-07 Transmission System Planning Performance Requirements for Extreme Weather | December 2024

2

Directive Language

FERC Order 896 Directives

P37. “Because the impact of most extreme heat and cold events spans
beyond the footprints of individual planning entities, it is important that all
responsible entities likely to be impacted by the same extreme weather
events use consistent benchmark events. Doing so is important to ensuring
that neighboring planning regions are assuming similar weather conditions
and are able to coordinate their assumptions accordingly. As a result,
defining the benchmark event in a manner that provides responsible
entities significant discretion to determine the applicable meteorological
conditions would not meet the objectives of this final rule.”
P38. “[I]n developing extreme heat and cold benchmark events, NERC shall
ensure that benchmark events reflect regional differences in climate and
weather patterns.”

Consideration of Directives

NERC, in consultation with climate data subject matter expert consultants
on benchmark events, developed subregions or “zones” of North America
that are likely to experience similar weather conditions. These zones also
consider practical concerns with coordination such as the boundaries of
Interconnections and Balancing Authority Areas.
The drafting team developed Requirement R2 such that PCs within the
same zone are required to select one common extreme heat benchmark
temperature event and one common extreme cold benchmark
temperature event. This process balances the opportunity to provide input
with the need for common events to be modeled over wide areas.
NERC, in consultation with climate data subject matter expert consultants
on benchmark events, has utilized publicly available modeled data in the
last forty-three years (1980-2022), as well as more than eighty years of
projected hourly meteorology data from PNNL to ensure regional
differences in climate and weather patterns are reflected in the zones
depicted in Attachment 1 of TPL-008-1.
A Map has been added to the TPL-008-1 Standard showing the zones split
throughout the US and Canada. These are to be considered wide area, and
regional differences went into consideration when developing the data
based on extreme historical events over the past 40 years.

P39. “We also direct NERC to include in the Reliability Standard the
framework and criteria that responsible entities shall use to develop from
the relevant benchmark event planning cases to represent potential
weather-related contingencies (e.g., concurrent/correlated generation and
transmission outages, derates) and expected future conditions of the
system such as changes in load, transfers, and generation resource mix,
and impacts on generators sensitive to extreme heat or cold, due to the
weather conditions indicated in the benchmark events. Developing such a

The directive is addressed in Requirements R3 and R4 of the proposed TPL008-1 standard.
Requirement R3 obligates the PC to implement a process to coordinate the
development of the benchmark planning cases and sensitivity cases. This
process shall include: 1) the selection of System models within the LongTerm Transmission Planning Horizon to serve as a starting point for the
benchmark planning cases, 2) forecasted seasonal and temperature

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framework would provide a common design basis for responsible entities
to follow when creating benchmark planning cases. This would not only
help establish a clear set of expectations for responsible entities to follow
when developing benchmark planning events, but also facilitate auditing
and enforcement of the Standard.”

P40. “We also direct NERC to ensure the reliability standard contains
appropriate mechanisms for ensuring the benchmark event reflects up-todate meteorological data.”

P50. “[W]e…direct NERC to require that transmission planning studies
under the new or revised Reliability Standard consider the wide-area
impacts of extreme heat and cold weather. We direct NERC to clearly
describe the process that an entity must use to define the wide-area
boundaries. While commenters provide various views in favor of both a
geographical approach and electrical approach to defining wide-area
boundaries, we do not adopt any one approach in this final rule…NERC
should consider the comments in this proceeding when developing a new
or modified reliability standard that considers the broad area impacts of
extreme heat and cold weather.”

Consideration of Directives

dependent adjustments for Load, generation, Transmission, and transfers
within the zone to represent the selected benchmark temperature events,
3) assumed seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers outside of the zone as needed, and
4) the identification of changes to at least one of generation, real and
reactive forecasted load, or transfers to serve as a sensitivity case.
Requirement R4 obligates the responsible entity to develop benchmark
planning cases and sensitivity cases for performing the Extreme
Temperature Assessment which reflects System conditions from the
selected benchmark events. Requirement R4 also references the NERC
MOD-032 Reliability Standard that provides PCs and Transmission Planners
a mechanism for obtaining the data needed to develop the benchmark
planning cases.
Requirement R2 Part 2.1 requires that the temperature data collected to
identify benchmark temperature events includes 40 years of data “ending
no more than 5 years prior to the time the benchmark temperature events
are selected”. This requirement ensures that the window of time
considered for benchmark temperature events reflects up-to-date data.
The up-to five-year gap was included due to potential lags in data sources.
To understand the complexities of defining wide-area boundaries, the
drafting team reviewed the extreme weather events mentioned within
FERC Order No. 896, as well as the comments received during the FERC
Order proceeding. In addition, NERC consulted with climate data subject
matter experts who evaluated publicly available modeled data in the last
forty-three years (1980-2022) and more than eighty years of projected
hourly meteorology data from PNNL.
The drafting team struck a balance between a geographical approach and
an electrical approach by dividing North America into zones that are likely
to experience similar weather conditions but also consider practical

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P58. “[W]e…direct NERC to develop benchmark events for extreme heat
and cold weather events through the Reliability Standards development
process. We agree … that the development of adequate benchmark events
is critical and should be committed to the subject matter experts on the
standards drafting team. ”
P59. Further, requiring NERC to develop the new or modified Reliability
Standard’s benchmark events is consistent with the approach the
Commission took in Order No. 779, when the Commission directed NERC to
develop benchmark events for geomagnetic disturbance analyses.1 For
the same reasons, we also conclude that NERC is best positioned to define
mechanisms to periodically update extreme heat and cold weather
benchmark events, as discussed above.

Consideration of Directives

concerns with coordination such as the boundaries of Interconnections and
Balancing Authority Areas. These zones are depicted in Attachment 1 of
TPL-008-1, and PCs will be required to coordinate with all PCs in the zone(s)
they belong to.
The drafting team considered various approaches to developing benchmark
temperature events. With assistance from NERC’s subject matter expert
consultants, the drafting team identified the key components of
temperature events that are necessary for the event to constitute an
adequate benchmark temperature event. These components were
included in Requirement R2.
Specifically, based on the available data, the drafting team determined that
extreme benchmark temperature events must: 1) consider no less than
forty years of historical temperature data, 2) include recent temperature
data due to ongoing climate changes, and 3) represent one of the twenty
worst extreme temperature conditions over the forty year period based on
a 3-day rolling average of daily maximum (heat) or minimum (cold)
temperatures.
The ERO will maintain a library of benchmark temperature events that
meet these requirements. Responsible entities will be able to review and
select benchmark temperature events from this library to assist with the
development of benchmark planning cases. However, responsible entities
may also identify benchmark temperature events via their own processes
provided that the event meets the criteria of Requirement R2 and is agreed
upon by all PCs within the zone.

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P60. “[W]e…direct NERC to designate the type(s) of entities responsible for
developing benchmark planning cases and conducting wide-area studies
under the new or modified Reliability Standard…benchmark planning cases
should be developed by registered entities such as large planning
coordinators, or groups of planning coordinators, with the capability of
planning on a regional scope.”
P61: “We believe the designated responsible entities should have certain
characteristics, including having a wide-area view of the Bulk-Power
System and the ability to conduct long-term planning studies across a wide
geographic area. The responsible entities should also have the planning
tools, expertise, processes, and procedures to develop benchmark planning
cases and analyze extreme weather events in the long-term planning
horizon.”
P62: “To comply with this directive, NERC may designate the tasks of
developing benchmark planning cases and conducting wide-area studies to
an existing functional entity or a group of functional entities (e.g., a group
of planning coordinators). NERC may also establish a new functional entity
registration to undertake these tasks. In the petition accompanying the
proposed Reliability Standard NERC should explain how the applicable
registered entity or entities meet the objectives outlined above.”

Consideration of Directives

In addition to describing the minimum requirements of a benchmark
temperature event, Requirement R2 obligates PCs within the same zone to
coordinate in selecting one common extreme heat benchmark
temperature event and one common extreme cold benchmark
temperature event for completing the Extreme Temperature Assessment.
This coordination is required to ensure the benchmark temperature event
is reflected over a wide-area.
The drafting team discussed that the Transmission Planner (TP) and/or
Planning Coordinator (PC) would be the responsible entities to address TPL008-1 Requirements. Requirement R1 obligates both the TP and PC to
identify their individual and joint responsibilities.
Requirement R3 obligates each PC to implement a process for coordinating
the development of benchmark planning cases and sensitivity cases, using
the selected benchmark temperature events identified in Requirement R2.
This process must be implemented in coordination with all PCs within the
same zone.
Requirement R4 obligates each responsible entity, as identified in
Requirement R1, to use the coordination process developed in accordance
with Requirement R3 and data consistent with that provided in accordance
with the MOD-032 standard, supplemented by other sources as needed, to
develop benchmark planning cases and sensitivity cases.
The identification of joint and individual responsibilities in Requirement R1
provides a measure of flexibility for PCs and TPs to agree on a distribution
of responsibilities. Thus, while PCs are responsible for implementing the
case development process in Requirement R3, TPs may be responsible for
providing data and completing the case development according to that
process.

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P72. “[W]e direct NERC to require functional entities to share with the
entities responsible for developing benchmark planning cases and
conducting wide-area studies the system information necessary to develop
benchmark planning cases and conduct wide-area studies. Further,
responsible entities must share the study results with affected transmission
operators, transmission owners, generator owners, and other functional
entities with a reliability need for the studies.”

Consideration of Directives

The development of benchmark planning cases and sensitivity cases will
require cooperation amongst many PCs and TPs. By requiring participation
from all entities within a zone, TPL-008-1 ensures that the group of
functional entities have a sufficient wide-area view of the Bulk Power
System and the planning tools, expertise, processes and procedures
necessary for developing benchmark planning cases and sensitivity cases.
The directive is addressed in proposed TPL-008-1 in Requirements R3, R4
and R11.
Requirement R3 obligates each PC to implement a process for coordinating
the development of benchmark planning cases, using the selected
benchmark temperature events identified in Requirement R2, among all
Planning Coordinators within a zone.
Requirement R4 obligates each responsible entity, as identified in
Requirement R1, to use the coordination process implemented in
accordance with Requirement R3 and data consistent with that provided in
accordance with the MOD-032 standard, supplemented by other sources as
needed, to develop benchmark planning cases and sensitivity cases.

P73. “Because in this final rule we direct NERC to determine the
responsible entities that will be developing benchmark planning cases and
conducting wide-area studies, it is possible that the selected responsible
entities under the new or modified Reliability Standard will not be able to
request and receive needed data pursuant to MOD-032-1, absent
modification to that Standard.”

Requirement R11 obligates each responsible entity, as identified in
Requirement R1, to provide its Extreme Temperature Assessment results
within 60 calendar days of a request to any functional entity that has a
reliability related need and submits a written request for the information.
The drafting team discussed and determined that data needed to address
the Extreme Temperature Assessment would still be appropriate to receive
through MOD-032. MOD-032 ensures an adequate means of data
collection for transmission planning and requires applicable registered
entities to provide steady-state, dynamic, and short circuit modeling data
to their Transmission Planner(s) and Planning Coordinator(s). As outlined in
Requirement R1 and Attachment 1 of MOD-032, MOD-032 allows various

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P76: “[W]e…direct NERC to address the requirement for wide-area
coordination through the standards development process, giving due
consideration to relevant factors identified by commenters in this
proceeding.”
P77. “[W]e direct NERC to require in the new or modified Reliability
Standard that responsible entities share the results of their wide-area
studies with other registered entities such as transmission operators,
transmission owners, and generator owners that have a reliability related
need for the studies.”
P88. “[W]e direct NERC to require under the new or revised Reliability
Standard the study of concurrent/correlated generator and transmission
outages due to extreme heat and cold events in benchmark events as
described in more detail below.”
P92. “These contingencies (i.e., correlated/concurrent, temperature
sensitive outages, and derates) shall be identified based on similar

Consideration of Directives

data collection such as in-service status and capability associated with
demand, generation, and transmission associated with various case types,
scenarios, system operating states, or conditions for the long-term
planning horizon. MOD-032 also requires applicable registered entities to
provide “other information requested by the Planning Coordinator or
Transmission Planner necessary for modeling purposes” for each of the
three types of data required. Because the drafting team determined the
responsible entities that will be developing benchmark planning cases are
limited to Planning Coordinators and Transmission Planners, they will be
able to request and receive needed data pursuant to MOD-032. Thus, the
drafting team believes that there is no need to update MOD-032.
The drafting team reviewed all the extreme weather events mentioned
within the FERC Order 896. For this project, the drafting team focused the
scope of Requirement R3 to require each PC to implement a process for
coordinating the development of benchmark planning cases and sensitivity
cases, using the selected benchmark temperature events identified in
Requirement R2, among all PCs within a zone.
This directive is addressed in proposed TPL-008-1 Requirement R11.
Requirement R11 obligates each responsible entity to provide the widearea study results within 60 calendar days of a request to any functional
entity that has a reliability related need and has submitted a written
request for the information.
This directive is addressed in proposed TPL-008-1 through Requirements R3
and R4. Per Requirement R3 Part 3.2, the benchmark planning case
development process must include forecasted seasonal and temperature
dependent adjustments for Load, generation, Transmission, and transfers
within the zone. Per Requirement R4, the data necessary to build the
benchmark planning cases must be provided via MOD-032, supplemented
by other sources as needed. Any concurrent/correlated generator and
transmission outages due to extreme heat and cold events in benchmark

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Consideration of Directives

contingencies that occurred in recent extreme weather events or expected
to occur in future forecasted events.”

temperature events should be reflected in the model data and thus
represented in the initial conditions of the benchmark planning cases.

P111. “[W]e direct NERC to require in the proposed new or modified
Reliability Standard that responsible entities perform both steady state and
transient stability (dynamic) analyses in the extreme heat and cold weather
planning studies. In a steady state analysis, the system components are
modeled as either in-service or out-of-service and the result is a single
point-in-time snapshot of the system in a state of operating equilibrium. A
transient stability (dynamic) analysis examines the system from the start to
the end of a disturbance to determine if the system regains a state of
operating equilibrium. Performing both analyses ensures that the system
has been thoroughly assessed for instability, uncontrolled separation, and
cascading failures in both the steady state and the transient stability
realms.” (internal citations omitted).
P112. “[W]e direct NERC to define a set of contingencies that responsible
entities will be required to consider when conducting wide-area studies of
extreme heat and cold weather events under the new or modified
Reliability Standard. We believe that it is necessary to establish a set of
common contingencies for all responsible entities to analyze. Required
contingencies, such as those listed in Table 1 of Reliability Standard TPL001-5.1 (i.e., category P1 through P7), establish common planning events
that set the starting point for transmission system planning assessments.
Requiring the study of predefined contingencies will ensure a level of
uniformity across planning regions—a feature that will be necessary in the
new or revised Reliability Standard considering that extreme heat and cold
weather events often exceed the geographic boundaries of most existing
planning footprints.”

This directive is addressed in proposed TPL-008-1 through Requirement R8
and Table 1.
Requirement R8 requires the responsible entity to complete both steady
state and transient stability analyses and document the assumptions and
results.
Table 1 obligates each responsible entity to perform both steady state and
transient stability analyses and compare the study results against steady
state and stability performance requirements.
This directive is addressed in proposed TPL-008-1 through Requirement R7
and Table 1.
Requirement R7 requires the responsible entity to identify Contingencies
for completing the Extreme Temperature Assessment. The rationale, for
those Contingencies selected for evaluation, shall be available as
supporting information.
The Contingencies for each category in Table 1 of TPL-008-1 correspond to
the well-established Contingencies defined in Reliability Standard TPL-0015.1. Utilizing these well-established Contingencies will ensure a level of
uniformity across planning regions.

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P113: “[T]he contingencies required in the new or revised Reliability
Standards should reflect the complexities of transmission system planning
studies for extreme heat and cold weather events.”
P116. “[W]e direct NERC to require in the new or modified Reliability
Standard that responsible entities model demand load response in their
extreme weather event planning area. As indicated by several
commenters, because demand load response is generally a mitigating
action that involves reducing distribution load during periods of stress to
stabilize the Bulk-Power System, its effect during an extreme weather
event should be modeled.”
P 117: “[I]n addressing this directive, we expect NERC to determine
whether responsible entities will need to take additional steps to ensure
that the impacts of demand load response are accurately modeled in
extreme weather studies, such as by analyzing demand load response as a
sensitivity, as is currently the case under Reliability Standard TPL-001-5.1.”
P124. “[W]e direct NERC to require the use of sensitivity cases to
demonstrate the impact of changes to the assumptions used in the
benchmark planning case. Sensitivity analyses help a transmission planner
to determine if the results of the base case are sensitive to changes in the
inputs. The use of sensitivity analyses is particularly necessary when
studying extreme heat and cold events because some of the assumptions
made when developing a base case may change if temperatures change –
for example, during extreme cold events, load may increase as
temperatures decrease, while a decrease in temperature may result in a
decrease in generation. We… direct NERC to define during the Reliability
Standard development process a baseline set of sensitivities for the new or
modified Reliability Standard. While we do not require the inclusion of any
specific sensitivity in this final rule, NERC should consider including
conditions that vary with temperature such as load, generation, and system
transfers.”

Consideration of Directives

TPL-008-1 Requirement R4 meets this directive by requiring each
responsible entity to develop benchmark planning cases using data
consistent with that provided in accordance with the MOD-032 standard,
supplemented by other sources as needed.
Specifically, Attachment 1 of MOD-032 requires information requested by
the Planning Coordinator or Transmission Planner necessary for modeling
purposes.

This directive is addressed in proposed TPL-008-1 in Requirement R3, which
requires all PCs within the same zone to coordinate to implement a process
for developing benchmark planning cases and sensitivity cases. Sensitivity
cases are used to demonstrate the impact of changes to the basic
assumptions used in the benchmark planning cases. Per Requirement R3
Part 3.4, PCs must include provisions in the case development process to
identify changes to generation, real and reactive forecasted Load, and/or
transfers to develop sensitivity cases.
The identification of changes for sensitivity cases within the coordinated
process of Requirement R3 addresses the directive that precludes
responsible entities from determining sensitivities alone. However, nothing
prevents responsible entities from conducting additional sensitivity studies
they find relevant to their planning areas.

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P125. “We do not agree ... that responsible entities alone should determine
the sensitivity cases that must be considered in the responsible entity’s
study. … We…believe that responsible entities should be free to study
additional sensitivities relevant to their planning areas…cooperation will be
necessary between responsible entities conducting extreme heat and
extreme cold weather studies and other registered entities within their
extreme weather study footprints to ensure the selection of appropriate
sensitivities.”
P134. “[W]e directs NERC to require in the new or modified Reliability
Standard the use of planning methods that ensure adequate consideration
of the broad characteristics of extreme heat and cold weather conditions.
We further direct NERC to determine during the standard development
process whether probabilistic elements can be incorporated into the new
or modified Reliability Standard and implemented presently by responsible
entities. If NERC identifies probabilistic elements which responsible entities
can feasibly implement and that would improve upon existing planning
practices, we expect the inclusion of those methods in the proposed
Reliability Standard.”
P138. “[W]e direct NERC to identify during the standard development
process any probabilistic planning methods that would improve upon
existing planning practices, but that NERC deems infeasible to include in
the proposed Reliability Standard at this time. If any such methods are
identified, NERC shall describe in its petition for approval of the proposed
Reliability Standard the barriers preventing the implementation of those
probabilistic elements. We intend to use this information to determine
whether and what next steps may be warranted to facilitate the use of
probabilistic methods in transmission system planning practices.”
P152. “[W]e direct NERC to require in the new or modified Reliability
Standard the development of extreme weather corrective action plans for

Consideration of Directives

The drafting team discussed probabilistic elements and determined while
probabilistic analysis would be a good step forward, it would be better
suited for the future as the methodology, process, and tools mature.
Probabilistic assessment of generation and transmission facilities for the
benchmark planning cases was discussed during the process of drafting the
TPL-008-1 standard. However, based on the actual extreme heat and
extreme cold events that have occurred, outages for generation and
transmission facilities were unique for each of these events. Thus, it was
challenging to draw correlation for the outages that occurred for different
extreme heat and cold events for different regions and different
timeframes. In addition, the data, available from these events, was limited
to perform an adequate probabilistic assessment. Due to these reasons,
the drafting team has decided not to pursue any probabilistic assessment
for the current TPL-008-1 standard. This, however, does not preclude
future development of probabilistic assessment when having additional
data, as well as mature methodology, process and tools that can provide
meaningful probabilistic assessment for generation and transmission
outages under extreme temperature conditions.
The directive is addressed in the proposed TPL-008-1 Requirement R9.

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specified instances when performance standards are not met. In addition,
as explained below, we direct NERC to develop certain processes to
facilitate interaction and coordination with applicable regulatory
authorities or governing bodies responsible for retail electric service as
appropriate in implementing a corrective action plan.”
P155: “[T]he Commission is not directing any specific result or content of
the corrective action plan.”
P157. “[W]e direct NERC to require in the new or modified Reliability
Standard the development of corrective action plans that include
mitigation for specified instances where performance requirements for
extreme heat and cold events are not met—i.e., when certain studies
conducted under the Standard show that an extreme heat or cold event
would result in cascading outages, uncontrolled separation, or instability.”
P158: “[W]e give NERC in this final rule the flexibility to specify the
circumstances that require the development of a corrective action plan.”
P165. “[w]e direct NERC to require in the new or modified Reliability
Standard that responsible entities share their corrective action plans with,
and solicit feedback from, applicable regulatory authorities or governing
bodies responsible for retail electric service issues.”
P167. “Further, because an important goal of transmission planning is to
avoid load shed, any responsible entity that includes non-consequential
load loss in its corrective action plan should also identify and share with
applicable regulatory authorities or governing bodies responsible for retail
electric service alternative corrective actions that would, if approved and
implemented, avoid the use of load shedding.”

Consideration of Directives

When the benchmark planning case study results indicate the System is
unable to meet performance requirements for P0 and P1 Contingencies,
Corrective Action Plans (CAPs) must be developed. Additionally, in
accordance with Requirement R9 Part 9.1, responsible entities shall make
their CAP available to, and solicit feedback from, applicable regulatory
authorities or governing bodies responsible for retail electric service issues.

The directive is addressed in the proposed TPL-008-1 Requirement R9.
When the benchmark planning case study results indicate the system is
unable to meet performance requirements for P0 and P1 Contingencies,
Corrective Action Plans must be developed.

The directive is addressed in the proposed TPL-008-1 Requirement R9.
Requirement R9.1 requires the responsible entities to make their CAP
available and solicit feedback from applicable regulatory authorities or
governing bodies responsible for retail electric service issues.
This directive is addressed in proposed TPL-008-1 Requirement R9.
As stipulated in Requirement R9 Part 9.2, when Non-Consequential Load
Loss is utilized as an element of a CAP for a Table 1 P1 Contingency, the
responsible entity must document the alternative(s) considered, and notify
the applicable regulatory authorities or governing bodies responsible for
retail electric service issues.

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P188. “[W]e direct NERC to submit a new or modified Reliability Standard
within 18 months of the date of publication of this final rule in the Federal
Register. Further, we direct NERC to propose an implementation timeline
for the new or modified Reliability Standard, with implementation
beginning no later than 12 months after the effective date of a Commission
order approving the proposed Reliability Standard.”

P193. “[W]e direct NERC to establish an implementation timeline for the
proposed Reliability Standard. In complying with this directive, NERC will
have discretion to develop a phased-in implementation timeline for the
different requirements of the proposed Reliability Standard (i.e.,
developing benchmark cases, conducting studies, developing corrective
action plans). However, this phased-in implementation must begin within
12 months of the effective date of a Commission order approving the
proposed Reliability Standard and must include a clear deadline for
implementation of all requirements.”

Consideration of Directives

The directive is addressed with the publication of TPL-008-1 and will be
filed with the regulatory government no later than December 23, 2024,
within 18 months of the date Order No. 896 was published in the Federal
Register.
The implementation plan addresses Requirement R1 becoming effective 12
months from the effective date of the Commission order approving the
TPL-008-1. In addition, phased-in approaches have been provided for other
Requirements needing additional time. See the TPL-008-1 Implementation
Plan.
The implementation plan addresses Requirement R1 becoming effective 12
months from the effective date of the Commission order approving the
TPL-008-1. In addition, phased-in approaches have been provided for other
Requirements needing additional time. See the TPL-008-1 Implementation
Plan.

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ERO Enterprise Process for TPL-008-1
Benchmark Weather Event Development and
Maintenance

Standards Development and Engineering Process Document
December 2024
Background

This Electric Reliability Organization (ERO) Enterprise Process for TPL-008-1 1 Benchmark Weather Event
Development and Maintenance addresses how ERO Enterprise staff will develop and maintain a library of
benchmark weather events (herein as the Weather Event Library) to be used by Planning Coordinators and
Transmission Planners for TPL-008-1 studies. Per Requirement R2 of TPL-008-1 and consistent with
directives outlined in FERC Order No. 896 2, Planning Coordinators and Transmission Planners will have
benchmark temperature events available, via the Weather Event Library to select from, when developing
their benchmark planning cases.

Purpose

The purpose of this process document is to formalize a repeatable approach to develop and maintain the
Weather Event Library. While both the TPL-008-1 study requirements and this process are in the initial
stages of development, it is essential that industry is informed of this process and how it will be designed
and implemented, following the completion of NERC Project 2023-07. This process document outlines an
initial set of process objectives and approach, but is not considered to be complete at this time. This
document will be revised, as needed, throughout the development of NERC Project 2023-07 and in future
updates of the benchmark temperature events.

Document Maintenance

NERC will maintain this document to ensure it is consistent with acceptable and publicly available practices.
This document will be reviewed as it is implemented. Updates will be made by NERC Standards
Development and Engineering, as needed, to reflect lessons learned as the process matures. Any
substantive changes to this process, supplemental/attached criteria, or other guidance to be used by NERC
in developing additional benchmark events, archiving/removing benchmark events, or other modifications
to the Weather Event Library, will be reviewed in consultation with NERC Legal, NERC Compliance
Assurance, Zone Entity staff, and FERC. Approved substantive revisions to this document will be detailed in
the Appendix and broadly communicated to industry.

1
2

Link pending final approval of TPL-008-1
FERC Docket No. RM22-10-000; Order No. 896; https://www.ferc.gov/media/e-1-rm22-10-000; June 15, 2023

RELIABILITY | RESILIENCE | SECURITY

Process Overview

The following is a five-year iterative process coinciding with Planning Coordinator and Transmission Planner
implementation of TPL-008-1. As TPL-008-1 and associated benchmark event(s) will be submitted to FERC
in December 2024, the first iteration of this process will cover five years.
•

•

•

•

•

December 2024


Weather Event Library developed and ready to go live for industry.



Benchmark Events, for the first five-years required per the TPL-008-1 Reliability Standard,
completed and uploaded to the Weather Event Library.

Year One:


ERO to provide Weather Event Library training.



ERO to engage with industry subject matter experts (SMEs), Planning Coordinators, research
labs, and trade organizations, and NERC technical committees on additional and updated criteria
for developing benchmark events.

Year Two:


ERO to initiate review of benchmark event criteria, identify any changes needed to the minimum
TPL-008 Requirement R2 criteria for consideration through the standard development process,
identify consideration of additional relevant factors/analysis that may be included in future EROdeveloped benchmark events, and incorporate feedback from year one.



ERO to deliver a webinar and industry outreach.

Year Three:


ERO to develop new benchmark events3 based on updated temperature data, with
consideration to any additional relevant factors that are identified.



ERO to update the Weather Event Library with updated benchmark events.

Year Four:


•

ERO will engage with industry subject matter experts (SMEs), Planning Coordinators, research
labs, and trade organizations, and NERC technical committees on additional future information
as needed.

Year Five:


ERO to conduct review of this process and make necessary revisions based on lessons-learned
and feedback (e.g., CMEP feedback loops, FERC, SMEs)



ERO to provide training on benchmark event process and changes to the TPL-008-1 Benchmark
Temperature Events Library 4.

Note: This is for the second iteration of benchmark events being developed.
Link to TPL-008-1 Benchmark Temperature Events Library:
https://www.nerc.com/pa/Stand/Project202307ModtoTPL00151TransSystPlanPerfReqExWe/TPL-008-1_Events.pdf

3
4

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

2

Year 1

• Deliver Weather Event Library Training
• Develop training and guidance for planning case development

Year 2

• Review and recommend modifications to benchmark event criteria as needed,
identify additional relevant factors for ERO-developed benchmarks
• Informational session/industry outreach

Year 3

• Update library with new/removed benchmark events
• Goal is to have process for updating benchmark events on year three of each
iteration

Year4
Year 5

• ERO to conduct review of this process and make necessary revisions based on
lessons-learned and feedback (e.g., CMEP feedback loops, FERC, SMEs)

• Review process and revise based on lessons learned and other feedback loops
• Update Weather Event Library training

Background for Initial TPL-008 R2 Criteria, Attachment 1 Planning Zones,
and
the
Initial
ERO
TPL-008-1
Benchmark
Temperature
Scoping

While the development of the extreme weather event library was intended to be comprehensive, it was
not exhaustive. Instead, this initial assessment is a part of a multi-year effort by NERC and industry to
develop a robust, North American weather dataset and detailed process for extreme weather events. In
the interim, this library of extreme heat and cold events has notable considerations:
•

Only extreme heat and cold temperature events were evaluated. The analysis did not assess other
weather events such as hydrologic droughts, wind and solar droughts, wildfires, hurricanes, or other
extreme weather events that could jeopardize grid reliability.

•

Only historical meteorological data was considered. The analysis did not incorporate climate
projections or future weather patterns.

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•

The analysis identified extreme events over a 43-year historical record and did not give higher
priority to recent events

•

The study is limited in identifying extreme events, not validating or explaining meteorological drivers
of that event

•

The analysis relied on historical reanalysis and modeled weather data, rather than historical
observed data for the United States (A smaller observed dataset was used for Canada).

Data Sources

A Pacific Northwest National Laboratory (PNNL) weather dataset 5, used in this study, consists of 43 years
(1980-2022) of historical hourly meteorology and roughly 80 years (2020-2099) of projected hourly
meteorology. Hourly observations were dynamically downscaled from historical reanalysis of ERA5 data
into higher temporal and spatial resolutions using the Weather Research and Forecasting Model (WRF). The
model resolution consisted of 12km2 areas that were spatially-averaged by county and then populationweighted to 54 Balancing Authorities (BAs) in the conterminous United States. The variables included in the
final BA weather data are listed in Table 1. While additional parameters like humidity, solar irradiance, and
wind speed are available in the dataset, the identification of extreme weather events in this study was solely
determined by the temperature value.
Table 1: Weather Variables in PNNL Dataset

The PNNL dataset and contributing model were chosen for this study due to the consistency, breadth and
granularity of the weather data. The availability of weather data at the BA-level coincides with topology
standards in power-system coordination in North America. Temperature observation methods can differ
zonally, so a standardized weather model, such as one in the PNNL dataset, offers unparallelled data
consistency across large geographical areas.
Topology

The zone topology is a function of Balancing Authority jurisdiction and general knowledge of zonal weather
patterns. The goal of the topology was to split the North American System into several distinct zones that
have similar electric power system properties (i.e. balancing authority and interconnections) and similar
weather or climatological patterns. In the United States, Balancing Authorities with large areas of
Burleyson, C., Thurber, T., & Vernon, C. (2023). Projections of Hourly Meteorology by Balancing Authority Based on the IM3/HyperFACETS
Thermodynamic Global Warming (TGW) Simulations (v1.0.0) [Data set]. MSD-LIVE Data Repository. https://doi.org/10.57931/1960530

5

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

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jurisdiction, exclusively ISOs and RTOs, are assigned their own weather zone. In geographical areas
comprised of multiple balancing authorities, generalized weather zones are created to best represent zonal
weather patterns.
Table 2: Balancing Authority to Weather Zone Mappings
Zone
Midwest North and
South
New England
Central US North
and South
Texas
New York
Central Atlantic
California
Pacific Northwest
Rocky Mountain
Great Basin
Southwest
Southeast
Florida

Balancing Authorities
MISO
ISONE
SPP
ERCOT
NYISO
PJM
5 balancing authorities
10 balancing authorities
3 balancing authorities
4 balancing authorities
6 balancing authorities
7 balancing authorities
9 balancing authorities

In addition to the 15 weather zones representing the United States, five weather zones were developed to
represent Eastern, Central, and Western Canada. The PNNL weather dataset does not contain data for
Canada, so this study compiled observed weather data from weather stations in the lower Canadian
Provinces. The 20 weather zones best represent the area of study and complement the granularity of
available data. A graphical representation of the final weather zones is shown in Figure 1.
Table 3: Canadian Weather Stations to Weather Zone Mappings.
Weather Zones
Eastern Canada
(Ontario,
Quebec, and
Maritimes)

Province
Ontario
Quebec
New Brunswick
Nova Scotia
Saskatchewan
Central Canada
Manitoba
British Columbia
Western Canada
Alberta

Weather Stations
1 weather station
3 weather stations
1 weather station
1 weather station
2 weather stations
1 weather station
2 weather stations
2 weather stations

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Figure 1: North American Weather Zones for Extreme Weather Events

Event Selection Process

Extreme weather events are defined in this study as extremely hot or cold multi-day events spanning across
multiple weather zones. The process to select these extreme events used temperature as the sole defining
variable, with emphasis placed on date ranges where multiple weather zones were experiencing historically
hot or cold temperatures.
Aggregating balancing authority data to geographical weather zones

Following the topology detailed above, the hourly temperature observations from either the PNNL weather
dataset or Canadian weather stations are assigned to weather zones. For each balancing area in the United
States, the PNNL data is aggregated from a county-level basis up to the balancing authority based on the
population in each county. The balancing authority temperature aggregation was therefore provided in the
PNNL dataset.
Additional aggregations were required to develop an average minimum, average, and maximum
temperature for zones with multiple balancing authorities in the Northwest, Southwest, and Southeast. In
these weather zones, the hourly temperature of each balancing authority was weighted by the 2022 peak
load value reported in the EIA Form-861 database. For the Canadian zones, weather station temperature
observations were assigned to the nearest population center and weighted by 2021 Census population.

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

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Calculating Three-Day Rolling Average Min/Max Temperatures

Rather than isolating single hours of extreme weather, the rolling 3-day average of minimum and maximum
daily temperatures are chosen to represent prolonged periods of extreme weather. The three-day
averaging period is centered on every day in the data set (January 1, 1980, to December 31, 2022) and
identifies the average minimum and maximum temperature from the day before, day of, and day after. The
output of this process develops a dataset of multi-day minimum and maximum temperatures to filter out
individual days of extreme heat or cold under the assumption that the power system is more challenged by
sustained periods of extreme heat or cold due to cumulative effects on increasing demand and generator
outages.
Selecting and Ranking Extreme Weather Events by Severity

Once 3-day average temperatures were calculated for every day, the forty coldest minimum values and
forty warmest maximum values were isolated and ranked for each zone, with rank 1 illustrating the most
extreme event. To avoid overlap of events within the same period, any ranked weather events within one
week of another would be removed in favor of the most extreme event. For example, if a zone’s seventhand tenth-most extreme event occur within a 7-day period, only the day with the seventh-most extreme
event would remain in the event database. As a result, some zones may have a discontinuous ranked list
given the removal of “duplicate” events.
A similar one-week overlap method was developed to group contemporaneous extreme weather events
amongst weather zones. First, all event dates were expanded to have a one-week “overlap period” centered
on each date. Then, beginning with the earliest event date, all events that share at least one day of their
overlap periods with the selected event date’s overlap period, will be grouped together. The final event
date range will take the earliest and latest dates of all grouped event overlap periods.
The design of the distinct event date ranges encourages multiple weather zones to share extreme weather
events over the course of a one- to two-week event period. To graphically represent the shared extreme
events, all event ranges are listed with the affected zones’ ranks in west-to-east order. A final shortlist of
extreme weather events was developed across all zones. This list included the top one and two most
extreme events, done separately for heat and cold periods. Events that included at least three zones
experience a top five event simultaneous was also included. For example, if PJM, NYISO, and ISONE all
experienced a top five extreme event, but it was not a top one or two event for any zone in isolation, the
event was included in the final shortlist.
Results

The result tables show the filtered list of event date ranges with the event ranks for each affected zone; a
lower rank represents a more extreme event and is shaded darker.
Cold Events

The cold events demonstrate more concentrated events among nearby zones, with the most extreme
temperature event occurring December 20th to December 29th, 1983. The event uniquely spanned across
the conterminous United States and yielded top ten coldest 3-day average minimum temperatures in 10
different weather zones.

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

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Under these results, the following cold events are recommended for the TPL-008-1 Benchmark
Temperature Event Library:
•

•

•

12/17/1990 – 1/2/1991 for the Western U.S. and Western part of Canada


12/21 for Pacific NW



12/22 for Rocky Mountain, Great Basin, California



12/23 for Southwest



12/29 for Western Canada

12/19/1989 – 12/27/1989 for Central and Southeast U.S. and Central part of Canada


12/23 for Central Canada



12/24 for Central US



12/25 for Texas, ERCOT, Midwest, Southeast



12/26 for Florida

1/13/1994 – 1/29/1994 for the Northeast U.S. and Canada


1/16 for New England, Ontario, Quebec and Maritimes



1/20 for Central Atlantic, New York

It is important to note that these weather events do not affect all zones simultaneously, but instead move
across the continent in predictable patterns. This has important implications for power system operations
and reliability as load and generator availability may be affected in different zones in different times. An
example of this is from the 1983 event shown geographically in Figure 2. In this example, the worst case
does not occur at the same time in each zone and ideally multiple time periods should be assessed by the
planning coordinators.

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Figure 2: Snippets of Animated Weather Event Temperature Map

Heat Events

The heat events used are more numerous and disparate from one another. In other words, while extreme
cold events tend to affect large geographies simultaneously, heat events can be more localized. The
unconcentrated nature of heat events makes selecting the most extreme event more ambiguous.
Under these results, the following heat events are recommended for the NERC TPL-008-1 Benchmark
Temperature Event Library:

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

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•

•

•

7/13/2006 – 7/26/2006 for the Western U.S. and Western part of Canada


7/16 for Rocky Mountain, Great Basin



7/22 for Western Canada, Pacific NW



7/23 for California, Southwest

6/21/2012 – 7/9/2012 for Central and Southeast U.S. and Central part of Canada


6/26 for Texas ERCOT



6/28 for Central Canada, Central US



6/30 for Southeast, Florida



7/5 for Midwest

7/16/2021 – 7/25/2021 for the Northeast U.S. and Eastern part of Canada


7/21 for Central Atlantic, Ontario, Quebec and Maritimes



7/22 for New York, New England

Recommendations

The results of this study should inform planning coordinators of potential dates of when to study power
system conditions under extreme weather scenarios. While the final selection of event date ranges aligns
with historical records of extreme weather, a few recommendations and considerations should be made
before proceeding with this study’s results.
•

Planning coordinators should assess the entire list of distinct events shown and determine which
events were the most extreme for their jurisdiction along with neighboring areas.

•

Modeled temperature data provides widespread consistency of weather data across many years
and many zones. Observed temperature data can recognizably vary from modeled values due to the
variety of observation methods at individual weather stations. The temperatures derived from the
PNNL dataset for the extreme weather event selection can be provided, but actual temperature
values used in planning scenarios may need to be derived from observed weather records for local
consistency.

•

While temperature is a strong indicator of extreme weather events, it is not the only indicator
available in historical weather data sets. The inclusion of other weather variables such as humidity
and wind speed could further quantify the severity of extreme weather events.

•

Care should be taken when developing wind, solar, and generator de-rates or outage assumptions
in the planning cases, using meteorological information to dispatch.

•

Exceptions need to be accounted for – including HVDC and switchable units.

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

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TPL-008-1 ERO Enterprise Benchmark Weather Event Development and Maintenance
Process Document Version History
Version
1

Date
TBD

Owner
Standards Staff

Change tracking
Initial Version

ERO Enterprise Process for TPL-008-1 Benchmark Weather Event Development and Maintenance

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TPL-008-1 Benchmark Temperature Events
November 2024

The below provides extreme heat and extreme cold benchmark temperature event data per the zones identified in Attachment 1 of the TPL008-1 Standard. Should entities not agree with the data provided below, you are welcome to coordinate with all Planning Coordinators within
your zone to developing one common extreme heat benchmark temperature event and one common extreme cold benchmark temperature
event per Requirement R2.
Zone

Daily Data

Canada Central
Florida
ISO-NE
Maritimes
MISO North
MISO South
NYISO
Ontario
PJM
SERC
SPP North
SPP South

Daily
Daily
Daily

California/Mexico
Great Basin
Rocky Mtn
Pacific NW

Daily
Daily
Daily
Daily

Daily
Daily
Daily

Daily
Daily
Daily
Daily
Daily
Daily

Benchmark Events
Top 40 Hottest/Coldest 3-Day Average
Eastern Interconnection
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Top 40
Western Interconnection
Top 40
Top 40
Top 40
Top 40

Hourly Data Selected Events
N/A
Hourly
Hourly
N/A
Hourly
Hourly
Hourly
N/A
Hourly
Hourly
Hourly
Hourly
Hourly
Hourly
Hourly
Hourly

RELIABILITY | RESILIENCE | SECURITY

WECC Southwest
Canada West

Daily
Daily

ERCOT

Daily

Quebec

Daily

TPL-008-1 Benchmark Temperature Events | November 2024

ERCOT Interconnection
Quebec Interconnection

Top 40
Top 40

Hourly
N/A

Top 40

Hourly

Top 40

N/A

NERC TPL-008 Data Library Documentation
Daily Data
Daily temperature statistics by Weather Zone.
● Region: The weather region associated with the data
● Date: Date in mm/dd/yyyy format
● Daily_Min_Temp: Minimum hourly temperature recorded on the associated date (F)
● Daily_Avg_Temp: Average hourly temperature recorded on the associated date (F)
● Daily_Max_Temp: Minimum hourly temperature recorded on the associated date (F)
● 3_Day_Rolling_Avg_Max_Temp: Three-day rolling average of daily maximum temperature (F)
● 3_Day_Rolling_Avg_Min_Temp: Three-day rolling average of daily minimum temperature (F)

Top 40 Events
Top 40 hottest and coldest days in each weather zone, measured by 3-day rolling average temperatures
● Region: The weather region associated with the data
● Event_Type: Heat Event or Cold Event
● Year: Year of associated event
● Month: Month of associated event
● Date: Date of associated event in mm/dd/yyyy format
● Daily_Min_Temp: Minimum hourly temperature recorded on the associated date (F)
● Daily_Avg_Temp: Average hourly temperature recorded on the associated date (F)
● Daily_Max_Temp: Minimum hourly temperature recorded on the associated date (F)
● 3_Day_Rolling_Avg_Max_Temp: Three-day rolling average of daily maximum temperature (F)
● 3_Day_Rolling_Avg_Min_Temp: Three-day rolling average of daily minimum temperature (F)
● Event_Temp: Temperature used to benchmark weather event (3_Day_Rolling_Avg_Max_Temp for Heat
Events, 3_Day_Rolling_Avg_Min_Temp for Cold Events)

Hourly Data (Filtered)
Hourly weather data from PNNL Dataset with modifications. Values are weighted if the region was represented by
multiple BAs. Values are filtered to only include Top 40 event days. Temperature converted from Kelvin to
Fahrenheit.
● Region: The weather region associated with the data
● Time_UTC: Datetime of hourly data in UTC timezone
● Temperature_F: Hourly temperature measured at 2-m (F)
● Q2: Specific humidity measured as 2-m water vapor mixing ratio (kg/kg)
● SWDOWN: Shortwave radiation measured as downwelling shortwave radiative flux at the surface (W/m²)
● SLW: Longwave radiation measured as radiative flux at the surface (W/m²)
● WSPD: Wind speed measured as 10-m wind speed (m/s)
For original data, including hourly data by county and balancing authority, please refer to:
Burleyson, C., Thurber, T., & Vernon, C. (2023). Projections of Hourly Meteorology by Balancing Authority Based on
the IM3/HyperFACETS Thermodynamic Global Warming (TGW) Simulations (v1.0.0) [Data set]. MSD-LIVE Data
Repository. https://doi.org/10.57931/1960530

Weather Zones

2

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

This is the final draft of the proposed standard.
Completed Actions

Date

Standards Committee approved Standard Authorization Request (SAR)
for posting

July 19, 2023

SAR posted for comment

August 8–September 27,
2023

45-day formal comment period with initial ballot

March 20–May 3, 2024

38-day formal comment period with additional ballot

July 16–August 22, 2024

15-day formal comment period with additional ballot

October 7–21, 2024

15-day formal comment period with additional ballot

November 7–21, 2024

Anticipated Actions

Date

5-day final ballot

December 2–6, 2024

Board adoption

December 10, 2024

Final Draft of TPL-008-1
December 2024

Page 1 of 24

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

New or Modified Term(s) Used in NERC Reliability Standards

This section includes all new or modified terms used in the proposed standard that will be
included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory
approval. Terms used in the proposed standard that are already defined and are not being
modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or
revised terms listed below will be presented for approval with the proposed standard. Upon
Board adoption, this section will be removed.
Term(s):

Extreme Temperature Assessment – Documented evaluation of future Bulk Electric System
performance for extreme heat and extreme cold benchmark temperature events.

Final Draft of TPL-008-1
December 2024

Page 2 of 24

TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements for Extreme
Temperature Events

2.

Number:

TPL-008-1

3.

Purpose:

Establish Transmission system planning performance requirements to
develop a Bulk Power System (BPS) that will operate reliably during
extreme heat and extreme cold temperature events.

4.

Applicability:
4.1. Functional Entities:
4.1.1. Transmission Planner
4.1.2. Planning Coordinator

5.

Effective Date: See Implementation Plan for Project 2023-07.

Final Draft of TPL-008-1
December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

B. Requirements and Measures
R1. Each Planning Coordinator shall identify, in conjunction with its Transmission
Planner(s), each entity’s individual and joint responsibilities for completing the
Extreme Temperature Assessment, which shall include each of the responsibilities
described in Requirements R2 through R11. Each responsible entity shall complete its
responsibilities such that the Extreme Temperature Assessment is completed at least
once every five calendar years. [Violation Risk Factor: Lower] [Time Horizon: Long-term
Planning]
M1. Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
provide dated documentation of each entity’s individual and joint responsibilities,
such as meeting minutes, agreements, copies of procedures, or protocols in effect
between entities or between departments of a vertically integrated system, or email
correspondence that identifies an agreement has been reached on individual and joint
responsibilities for completing the Extreme Temperature Assessment, and that these
responsibilities were completed such that the Extreme Temperature Assessment was
completed once every five calendar years.
R2. Each Planning Coordinator shall identify the zone(s) to which the Planning Coordinator
belongs to under Attachment 1 and shall coordinate with all Planning Coordinators
within each of its identified zone(s), to identify one common extreme heat benchmark
temperature event and one common extreme cold benchmark temperature event for
each of its identified zone(s) when completing the Extreme Temperature Assessment.
The benchmark temperature events shall be obtained from the benchmark library
maintained by the ERO or developed by the Planning Coordinators. Each benchmark
temperature event identified by the Planning Coordinators shall: [Violation Risk
Factor: High] [Time Horizon: Long-term Planning]
2.1. Consider no less than a 40-year period of temperature data ending no more than
five years prior to the time the benchmark temperature events are selected; and
2.2. Represent one of the 20 most extreme temperature conditions based on the
three-day rolling average of daily maximum (heat) or daily minimum (cold)
temperature across the zone.
M2. Each Planning Coordinator shall have evidence in either electronic or hard copy format
that it identified the zone(s) to which it belongs to, under Attachment 1, and that it
coordinated with all other Planning Coordinators within each of its identified zone(s)
to identify one common extreme heat benchmark temperature event and one
common extreme cold benchmark temperature event meeting the criteria of
Requirement R2 for each of their identified zone(s) when completing the Extreme
Temperature Assessment.
R3. Each Planning Coordinator shall coordinate with all Planning Coordinators within each
of its zone(s) identified in Requirement R2, to implement a process for developing
Final Draft of TPL-008-1
December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

benchmark planning cases for the Extreme Temperature Assessment that represent
the benchmark temperature events selected in Requirement R2 and sensitivity cases
to demonstrate the impact of changes to the basic assumptions used in the
benchmark planning cases. This process shall include the following: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
3.1. Selection of System models within the Long-Term Transmission Planning Horizon
to form the basis for the benchmark planning cases.
3.2. Forecasted seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers within the zone.
3.3. Assumed seasonal and temperature dependent adjustments for Load,
generation, Transmission, and transfers in areas outside the zone, as needed.
3.4. Identification of changes to at least one of the following conditions for sensitivity
cases: generation, real and reactive forecasted Load, or transfers.
M3. Each Planning Coordinator shall have dated evidence that it implemented a process
for coordinating the development of benchmark planning cases and sensitivity cases
for the Extreme Temperature Assessment as specified in Requirement R3.
R4. Each responsible entity, as identified in Requirement R1, shall use the process
developed in Requirement R3 and data consistent with that provided in accordance
with the MOD-032 standard, supplemented by other sources as needed, to develop
the following and establish category P0 as the normal System condition in Table 1:
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. One common extreme heat and one common extreme cold benchmark planning
case.
4.2. One common extreme heat and one common extreme cold sensitivity case.
M4. Each responsible entity, as identified in Requirement R1, shall have dated evidence in
either electronic or hard copy format that it developed benchmark planning cases and
sensitivity cases in accordance with Requirement R4.
R5. Each responsible entity, as identified in Requirement R1, shall have criteria for
acceptable System steady state voltage limits and post-Contingency voltage deviations
for completing the Extreme Temperature Assessment. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning]
M5. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of the documentation, specifying the criteria for
acceptable System steady state voltage limits and post-Contingency voltage deviations
for completing the Extreme Temperature Assessment.
R6. Each responsible entity, as identified in Requirement R1, shall define and document
the criteria or methodology to be used in the Extreme Temperature Assessment to
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December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

identify instability, uncontrolled separation, or Cascading within an Interconnection.
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
M6. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, specifying the criteria or
methodology to be used in the Extreme Temperature Assessment to identify
instability, uncontrolled separation, or Cascading within an Interconnection in
accordance with Requirement R6.
R7. Each responsible entity, as identified in Requirement R1, shall identify the
Contingencies for each category in Table 1 that are expected to produce more severe
System impacts on its portion of the Bulk Electric System. The rationale for those
Contingencies selected for evaluation shall be available as supporting information.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M7. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of the Contingencies for each
category in Table 1 that are expected to produce more severe System impacts on its
portion of the Bulk Electric System along with supporting rationale.
R8. Each responsible entity, as identified in Requirement R1, shall complete steady state
and transient stability analyses in the Extreme Temperature Assessment using the
Contingencies identified in Requirement R7, and shall document the assumptions and
results. Steady state and transient stability analyses shall be performed for the
following: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
8.1. Benchmark planning cases developed in accordance with Requirement R4 Part
4.1.
8.2. Sensitivity cases developed in accordance with Requirement R4 Part 4.2.
M8. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of the assumptions and results of
the steady state and transient stability analyses completed in the Extreme
Temperature Assessment.
R9. Each responsible entity, as identified in Requirement R1, shall develop a Corrective
Action Plan(s) when the analysis of a benchmark planning case, in accordance with
Requirement R8 Part 8.1, indicates its portion of the Bulk Electric System is unable to
meet performance requirements for category P0 or P1 in Table 1. For each Corrective
Action Plan, the responsible entity shall: [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
9.1. Document alternative(s) considered when Non-Consequential Load Loss is
utilized as an element of a Corrective Action Plan for a Table 1 P1 Contingency.
9.2. Be permitted to utilize Non-Consequential Load Loss as an interim solution,
which normally is not permitted for category P0 in Table 1 for situations that are
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December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

beyond the control of the Planning Coordinator or Transmission Planner that
prevent the implementation of a Corrective Action Plan in the required
timeframe, provided that the responsible entity documents the situation causing
the problem, alternatives evaluated, and takes actions to resolve the situation.
9.3. Make its Corrective Action Plan available to, and solicit feedback from, applicable
regulatory authorities or governing bodies responsible for retail electric service
issues.
9.4. Be permitted to have revisions to the Corrective Action Plan in subsequent
Extreme Temperature Assessments, provided that the planned Bulk Electric
System shall continue to meet the performance requirements of Table 1.
M9. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation, of each Corrective Action Plan
developed in accordance with Requirement R9 when the analysis of a benchmark
planning case indicates its portion of the Bulk Electric System is unable to meet
performance requirements for category P0 or P1 in Table 1. Evidence shall include
documentation of correspondence with applicable regulatory authorities or governing
bodies responsible for retail electric service issues and any revision history.
R10. Each responsible entity, as identified in Requirement R1, shall evaluate and document
possible actions designed to reduce the likelihood or mitigate the consequences and
adverse impacts of the event(s) if analyses conclude there could be instability,
uncontrolled separation, or Cascading within an Interconnection, for the following:
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
10.1. Table 1 P7 Contingencies in benchmark planning cases analyzed in accordance
with Requirement R8 Part 8.1.
10.2. Categories P0, P1, and P7 in Table 1 in sensitivity cases analyzed in accordance
with Requirement R8 Part 8.2.
M10. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as electronic or hard copies of documentation that it evaluated and documented
possible actions designed to reduce the likelihood or mitigate the consequences and
adverse impacts when the analyses conclude there could be instability, uncontrolled
separation, or Cascading within an Interconnection for Table 1 P7 Contingencies in
benchmark planning cases or categories P0, P1, or P7 in Table 1 in sensitivity cases.
R11. Each responsible entity, as identified in Requirement R1, shall provide its Extreme
Temperature Assessment results within 60 calendar days of a request to any
functional entity that has a reliability related need and submits a written request for
the information. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M11. Each responsible entity, as identified in Requirement R1, shall provide dated evidence,
such as email notices, documentation of updated web pages, or postal receipts
showing recipient, that it provided its Extreme Temperature Assessment to any

Final Draft of TPL-008-1
December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

functional entity who has a reliability need within 60 calendar days of a written
request.

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December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

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 period(s) 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 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 responsible entity shall retain evidence of compliance with each
requirement in this standard for five calendar years or one complete
Extreme Temperature Assessment cycle, whichever is longer.

1.3. Compliance Monitoring and Enforcement Program: “Compliance Monitoring
Enforcement Program” or “CMEP” means, depending on the context (1) the
NERC Compliance Monitoring and Enforcement Program (Appendix 4C to the
NERC Rules of Procedure) or the Commission-approved program of a Regional
Entity, as applicable, or (2) the program, department or organization within
NERC or a Regional Entity that is responsible for performing compliance
monitoring and enforcement activities with respect to Registered Entities’
compliance with Reliability Standards.

Final Draft of TPL-008-1
December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events
Steady State & Stability:
a. Instability, uncontrolled separation, or Cascading within an Interconnection, defined in accordance with Requirement R6,
shall not occur.
b. Consequential Load Loss as well as generation loss is acceptable as a consequence of any event excluding P0.
c. Simulate the removal of all elements that Protection Systems and other controls are expected to automatically disconnect
for each event.
d. Simulate Normal Clearing unless otherwise specified.
e. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such
adjustments are executable within the time duration applicable to the Facility Ratings.
Steady State Only:
f. Applicable Facility Ratings shall not be exceeded.
g. System steady state voltages and post-Contingency voltage deviations shall meet the criteria identified in Requirement R5.

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December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events

Category

P0
No
Contingency
P1
Single
Contingency

Initial
Condition

Normal
System

Normal
System

P7
Multiple
Contingency
(Common
Structure)

Normal
System

Final Draft of TPL-008-1
December 2024

Event1

Fault
Type3

None

N/A

Loss of one of the following:
1. Generator
2. Transmission Circuit
3. Transformer2
4. Shunt Device4

3Ø

5. Single Pole of a DC line

SLG

The loss of:
1. Any two adjacent (vertically
or horizontally) circuits on
common structure5
2. Loss of a bipolar DC line

SLG

Interruption
of Firm
Contingency
Transmission
BES Level
Service
Allowed

Non-Consequential Load Loss
Allowed
Benchmark
Planning
Cases

Sensitivity
Cases

N/A

Yes

No6

Yes

≥ 200 kV

Yes

Yes6

Yes

≥ 200 kV

Yes

Yes

Yes

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Table 1 – Steady State & Stability Performance Events
1. If the event analyzed involves BES elements at multiple System voltage levels, the lowest System voltage level of the
element(s) removed for the analyzed event determines the BES level of the event. For P7 events, the BES level of the event is
the highest System voltage level of the element(s) removed for the analyzed event.
2. For non-generator step up transformer outage events, the reference voltage, as used in footnote 1, applies to the low-side
winding (excluding tertiary windings). For generator and Generator Step Up transformer outage events, the reference
voltage applies to the BES connected voltage (high-side of the Generator Step Up transformer). Requirements which are
applicable to transformers also apply to variable frequency transformers and phase shifting transformers.
3. Unless specified otherwise, simulate Normal Clearing of faults. Single line to ground (SLG) or three-phase (3Ø) are the fault
types that must be evaluated in Stability simulations for the event described. A 3Ø or a double line to ground fault study
indicating the criteria are being met is sufficient evidence that a SLG condition would also meet the criteria.
4. Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
5. Excludes circuits that share a common structure for 1 mile or less.
6. Benchmark planning cases require the development of a Corrective Action Plan when the responsible entity’s portion of the
BES is unable to meet the performance requirements for categories P0 or P1. Additionally, in benchmark planning cases,
Non-Consequential Load Loss is not permitted for category P0 except where permitted as an interim solution in a Corrective
Action Plan in accordance with Requirement R9 Part 9.2.

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Violation Severity Levels
Violation Severity Levels

R#
R1.

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed less than
or equal to six months late.

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than six months but less than
or equal to 12 months late.

The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than 12 months but less than
or equal to 18 months late.

The Planning Coordinator, in
conjunction with its
Transmission Planner(s), failed
to identify individual and joint
responsibilities for completing
the Extreme Temperature
Assessment.
OR
The responsible entity
completed its individual and
joint responsibilities such that
the Extreme Temperature
Assessment was completed,
but it was completed more
than 18 months late.

R2.

N/A

Final Draft of TPL-008-1
December 2024

N/A

The Planning Coordinator
coordinated with all Planning
Coordinators within each
identified zone to identify one
common extreme heat and
one common extreme cold
benchmark temperature event
for completing the Extreme
Temperature Assessment, but
one of the identified events

The Planning Coordinator
coordinated with all Planning
Coordinators within each
identified zone to identify one
common extreme heat and
one common extreme cold
benchmark temperature event
for completing the Extreme
Temperature Assessment, but
both of the identified events

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

failed to meet all the criteria of failed to meet all of the criteria
Requirement R2.
of Requirement R2.
OR
The Planning Coordinator
failed to coordinate with all
Planning Coordinators within
each identified zone to identify
one common extreme heat
and one common extreme
cold benchmark temperature
event for completing the
Extreme Temperature
Assessment.
R3.

N/A

N/A

N/A

The Planning Coordinator did
not coordinate with all
Planning Coordinators within
each of its identified zone(s) to
implement a process for
developing benchmark
planning cases.
OR
The Planning Coordinator
coordinated with all Planning
Coordinators within each of its
identified zone(s) to
implement a process for
developing benchmark
planning cases, but the
process did not include all of
the required elements.

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December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R4.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
did not use the process
developed in Requirement R3
to develop benchmark
planning cases or sensitivity
cases.
OR
The responsible entity, as
identified in Requirement R1,
used the process developed in
Requirement R3 to develop
benchmark planning cases and
sensitivity cases, but did not
use data consistent with that
provided in accordance with
the MOD-032 standard,
supplemented by other
sources as needed, for one or
more of the required cases.
OR
The responsible entity, as
identified in Requirement R1,
used the process developed in
Requirement R3 and data
consistent with that provided
in accordance with the MOD032 standard, supplemented
as needed, but failed to
develop one or more of the
required planning or sensitivity
cases.

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December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R5.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
did not have criteria for
acceptable System steady
state voltage limits and postContingency voltage
deviations for completing the
Extreme Temperature
Assessment.

R6.

N/A

N/A

N/A

The responsible entity, as
identified in Requirement R1,
failed to define or document
the criteria or methodology to
be used in the Extreme
Temperature Assessment to
identify instability,
uncontrolled separation, or
Cascading within an
Interconnection.

R7.

N/A

N/A

The responsible entity, as
identified in Requirement R1,
identified Contingencies for
each category in Table 1 that
are expected to produce more
severe System impacts on its
portion of the Bulk Electric
System, but did not include
the rationale for those
Contingencies selected for
evaluation as supporting
information.

The responsible entity, as
identified in Requirement R1,
did not identify Contingencies
for each category in Table 1
that are expected to produce
more severe System impacts
on its portion of the Bulk
Electric System.

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December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for
one or more sensitivity cases
in accordance with
Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document the assumptions for
one or more benchmark
planning cases in accordance
with Requirement R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document results for one or
more of the sensitivity cases in
accordance with Requirement
R8.

The responsible entity, as
identified in Requirement R1,
completed steady state and
transient stability analyses in
the Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, but failed to
document results for one or
more of the benchmark
planning cases in accordance
with Requirement R8.
OR
The responsible entity, as
identified in Requirement R1,
failed to complete steady state
or transient stability analyses
and document results in the
Extreme Temperature
Assessment using the
Contingencies identified in
Requirement R7, in
accordance with Requirement
R8.

R9.

N/A

Final Draft of TPL-008-1
December 2024

N/A

The responsible entity, as
identified in Requirement R1,
developed a Corrective Action
Plan in accordance with
Requirement R9, but failed to
make its Corrective Action
Plan available to, or solicit
feedback from, applicable

The responsible entity, as
identified in Requirement R1,
failed to develop a Corrective
Action Plan when the
benchmark planning case
study results indicate the
System is unable to meet
performance requirements for

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

regulatory authorities or
governing bodies responsible
for retail electric service
issues.

R10.

N/A

N/A

The responsible entity, as
identified in Requirement R1,
evaluated and documented
possible actions to reduce the
likelihood or mitigate the
consequences and adverse
impacts of the event(s) when
analyses conclude there could
be instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Part 10.1,
but failed to evaluate and
document possible actions
where required under
Requirement R10 Part 10.2.

the Table 1 P0 or P1
Contingencies.
OR
The responsible entity, as
identified in Requirement R1,
developed a Corrective Action
Plan, but it was missing one or
more of the elements of
Requirement R9 Part 9.1, 9.3
and 9.4 (as applicable).
The responsible entity, as
identified in Requirement R1,
evaluated and documented
possible actions to reduce the
likelihood or mitigate the
consequences and adverse
impacts of the event(s) when
analyses conclude there could
be instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Part 10.2,
but failed to evaluate and
document possible actions
where required under
Requirement R10 Part 10.1.
OR
The responsible entity, as
identified in Requirement R1,
failed to evaluate and
document possible actions to

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December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

reduce the likelihood or
mitigate the consequences
and adverse impacts of the
event(s) when analyses
conclude there could be
instability, uncontrolled
separation, or Cascading
within an Interconnection
where required under
Requirement R10 Parts 10.1
and 10.2.
R11.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 60 days but
less than or equal to 80 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 80 days but
less than or equal to 100 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 100 days but
less than or equal to 120 days
following the request.

The responsible entity, as
identified in Requirement R1,
provided its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who requested the
information in writing, but it
was more than 120 days
following the request.
OR
The responsible entity, as
identified in Requirement R1,
did not provide its Extreme
Temperature Assessment
results to functional entities
having a reliability related
need who submitted a written
request for the information.

D. Regional Variances
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December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

None.

E. Associated Documents
•

Implementation Plan for Project 2023-07

•

Technical Rationale Document

•

Consideration of Issues and Directives for FERC Order 896.

•

ERO Benchmark Event Library

•

TPL-008 Data Library Read Me

Final Draft of TPL-008-1
December 2024

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TPL-008-1 – Transmission System Planning Performance Requirements for Extreme Temperature Events

Version History
Version
1

Date
TBD

Final Draft of TPL-008-1
December 2024

Action

Change
Tracking

Addressing FERC Order 896

New Standard

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TPL-008-1 Supplemental Material

Attachment 1: Extreme Temperature Assessment Zones

The table below lists the zones to be used in the Extreme Temperature Assessment and
identifies the Planning Coordinators that belong to each zone. In accordance with Requirement
R2, each Planning Coordinator is required to identify the zone(s) to which it belongs. Planning
Coordinators, in different zones within a broader planning region, may use the same
benchmark temperature events for their respective benchmark planning cases, provided the
benchmark temperature events meet the criteria of Requirement R2 for each zone.
Zone
MISO North

MISO South
SPP North
SPP South
PJM
New England
New York
SERC
Florida
Central Canada
Ontario
Maritimes

Southwest
Pacific Northwest

Final Draft of TPL-008-1
December 2024

Planning Coordinators

Eastern Interconnection
Planning Coordinator(s) in MISO that serve
portions of MISO in Montana, North Dakota,
South Dakota, Minnesota, Iowa, Wisconsin,
Michigan, Indiana, Illinois, Missouri, and
Kentucky
Planning Coordinator(s) in MISO that serve
portions of Arkansas, Mississippi, Louisiana, and
Texas
Planning Coordinator(s) in portions of SPP that
serve Iowa, Montana, Nebraska, North Dakota,
and South Dakota.
Planning Coordinator(s) in portions of SPP that
serve Arkansas, Kansas, Louisiana, Missouri, New
Mexico, Oklahoma, and Texas.
Planning Coordinator(s) that serves PJM
Planning Coordinator(s) in NPCC that serve the six
New England States
Planning Coordinator(s) in NPCC that serve New
York
Planning Coordinator(s) in SERC, excluding those
that serve Florida and those in MISO, SPP, and
PJM
Planning Coordinator(s) in SERC that serve Florida
Planning Coordinator(s) that serve Saskatchewan
and Manitoba region of MRO
Planning Coordinator(s) in NPCC that serve
Ontario
Planning Coordinator(s) in NPCC that primarily
serve New Brunswick, Nova Scotia, Prince Edward
Island, and Northern Maine
Western Interconnection
Planning Coordinator(s) in the Southwest region
of WECC, including El Paso in West Texas
Planning Coordinator(s) in the Pacific Northwest
region of WECC

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TPL-008-1 Supplemental Material

Great Basin
Rocky Mountain
California/Mexico
Western Canada
ERCOT
Quebec

Final Draft of TPL-008-1
December 2024

Zone

Planning Coordinators
Planning Coordinator(s) in the Great Basin region
of WECC
Planning Coordinator(s) in the Rocky Mountain
region of WECC
Planning Coordinator(s) in the California/Mexico
region of WECC
Planning Coordinator(s) that primarily serve
British Columbia and Alberta region of WECC
ERCOT Interconnection
Planning Coordinator(s) in Texas that are part of
the ERCOT Interconnection
Quebec Interconnection
Planning Coordinator(s) that serve Quebec in the
NPCC Region.

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TPL-008-1 Supplemental Material

The map below depicts an approximation of the zones to be used in the Extreme Temperature
Assessment and is provided as a visual aid; to the extent that there is a conflict between the
map and the table, the table controls. This map is not to be used for compliance purposes.
TPL-008-1 Weather Zones Map

Final Draft of TPL-008-1
December 2024

Page 24 of 24

Reliability Standard Audit Worksheet1
TPL-008-1 – Transmission System Planning Performance Requirements for
Extreme Temperature Events
This section to be completed by the Compliance Enforcement Authority.
Audit ID:
Registered Entity:
NCR Number:
Compliance Enforcement Authority:
Compliance Assessment Date(s) 2:
Compliance Monitoring Method:
Names of Auditors:

Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
Registered name of entity being audited
NCRnnnnn
Region or NERC performing audit
Month DD, YYYY, to Month DD, YYYY
[On-site Audit | Off-site Audit | Spot Check]
Supplied by CEA

Applicability of Requirements
R1
R2
R3
R4
R5
R6
R7
R8
R9
R10
R11

BA

DP

GO

GOP

IA

LSE

PC
X
X
X
X
X
X
X
X
X
X
X

PSE

RC

RP

RSG

TO

TOP

TP
X

TSP

1 NERC developed this Reliability Standard Audit Worksheet (RSAW) language in order to facilitate NERC’s and the Regional Entities’ assessment of a registered entity’s
compliance with this Reliability Standard. The NERC RSAW language is written to specific versions of each NERC Reliability Standard. Entities using this RSAW should
choose the version of the RSAW applicable to the Reliability Standard being assessed. While the information included in this RSAW provides some of the methodology
that NERC has elected to use to assess compliance with the requirements of the Reliability Standard, this document should not be treated as a substitute for the
Reliability Standard or viewed as additional Reliability Standard requirements. In all cases, the Regional Entity should rely on the language contained in the Reliability
Standard itself, and not on the language contained in this RSAW, to determine compliance with the Reliability Standard. NERC’s Reliability Standards can be found on
NERC’s website. Additionally, NERC Reliability Standards are updated frequently, and this RSAW may not necessarily be updated with the same frequency. Therefore,
it is imperative that entities treat this RSAW as a reference document only, and not as a substitute or replacement for the Reliability Standard. It is the responsibility
of the registered entity to verify its compliance with the latest approved version of the Reliability Standards, by the applicable governmental authority, relevant to its
registration status.
The RSAW may provide a non-exclusive list, for informational purposes only, of examples of the types of evidence a registered entity may produce or may be asked to
produce to demonstrate compliance with the Reliability Standard. A registered entity’s adherence to the examples contained within this RSAW does not necessarily
constitute compliance with the applicable Reliability Standard, and NERC and the Regional Entity using this RSAW reserve the right to request additional evidence from
the registered entity that is not included in this RSAW. This RSAW may include excerpts from FERC Orders and other regulatory references which are provided for ease
of reference only, and this document does not necessarily include all applicable Order provisions. In the event of a discrepancy between FERC Orders, and the language
included in this document, FERC Orders shall prevail.
2 Compliance Assessment Date(s): The date(s) the actual compliance assessment (on-site audit, off-site spot check, etc.) occurs.

Limited Disclosure

NERC Reliability Standard
Audit Worksheet

Legend:
Text with blue background:
Fixed text – do not edit
Text entry area with green background: Entity-supplied information
Text entry area with white background: Auditor-supplied information
Findings
(This section to be completed by the Compliance Enforcement Authority)
Req.
Finding
Summary and Documentation
R1
R2
R3
R4
R5
R6
R7
R8
R9
R10
R11

Req.

Areas of Concern

Req.

Recommendations

Req.

Positive Observations

NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-008-1_2024_v1 Revision Date: November 2024 RSAW Template: RSAW2014R1.2
2
Limited Disclosure

Functions Monitored

NERC Reliability Standard
Audit Worksheet

Subject Matter Experts
Identify the Subject Matter Expert(s) responsible for this Reliability Standard.
Registered Entity Response (Required; Insert additional rows if needed):
SME Name
Title
Organization

NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-008-1_2024_v1 Revision Date: November 2024 RSAW Template: RSAW2014R1.2
3
Limited Disclosure

Requirement(s)

NERC Reliability Standard
Audit Worksheet

R1 Supporting Evidence and Documentation
R1.

Each Planning Coordinator shall identify, in conjunction with its Transmission Planner(s), each entity’s individual
and joint responsibilities for completing the Extreme Temperature Assessment, which shall include each of the
responsibilities described in Requirements R2 through R11. Each responsible entity shall complete its
responsibilities such that the Extreme Temperature Assessment is completed at least once every five calendar
years. [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]

M1.

Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall provide documentation of each
entity’s individual and joint responsibilities, such as meeting minutes, agreements, copies of procedures or
protocols, in effect between entities or between departments of a vertically integrated system, or email
correspondence that identifies an agreement has been reached on individual and joint responsibilities for
completing the Extreme Temperature Assessment and that these responsibilities were completed such that the
Extreme Temperature Assessment was completed once every five calendar years.

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Evidence Requested i:
Provide the following evidence, or other evidence to demonstrate compliance.
Documentation of each Entity’s individual and joint responsibility for completing the Extreme Temperature
Assessment.
Documentation that the Extreme Temperature Assessment and associated responsibilities were completed
once every five calendar years.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-008-1_2024_v1 Revision Date: November 2024 RSAW Template: RSAW2014R1.2
4
Limited Disclosure

NERC Reliability Standard
Audit Worksheet

Compliance Assessment Approach Specific to TPL-008-1, R1
This section to be completed by the Compliance Enforcement Authority
Verify an Extreme Temperature Assessment was completed once every five calendar years.
Verify the completion of entity’s individual and joint responsibilities for completing the Extreme
Temperature Assessment.
Review processes that identify each entity’s individual and joint responsibilities for completing the
Extreme Temperature Assessment at least once every five calendar years.
Note to Auditor: Extreme Temperature Assessment - Documented evaluation of future Bulk Electric System
performance for extreme heat and extreme cold benchmark temperature events.
Auditor Notes:

R2 Supporting Evidence and Documentation
R2.

Each Planning Coordinator shall identify the zone(s) to which the Planning Coordinator belongs to under
Attachment 1 and shall coordinate with all Planning Coordinators within each of its identified zone(s), to identify
one common extreme heat benchmark temperature event and one common extreme cold benchmark
temperature event for each of its identified zone(s) when completing the Extreme Temperature Assessment.
The benchmark temperature events shall be obtained from the benchmark library maintained by the ERO or
developed by the Planning Coordinators. Each benchmark temperature event identified by the Planning
Coordinators shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
2.1. Consider no less than a 40-year period of temperature data ending no more than five years prior to the time
the benchmark temperature events are selected; and
2.2. Represent one of the 20 most extreme temperature conditions based on the three-day rolling average of
daily maximum (heat) or daily minimum (cold) temperature across the zone.

M2.

Each Planning Coordinator shall have evidence in either electronic or hard copy format that it identified the
zone(s) to which it belongs to, under Attachment 1, and coordinated with all other Planning Coordinators within
each of its identified zone(s) to select one common extreme heat benchmark temperature event and one
common extreme cold benchmark temperature event meeting the criteria of Requirement R2 for each of their
identified zone(s) when completing the Extreme Temperature Assessment.

Registered Entity Response (Required):
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Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Documentation of identified zone(s) to which the entity belongs, under Attachment 1.
Documentation of one common extreme heat benchmark temperature event that was selected after
coordination with all Planning Coordinators within each of the identified zone(s).
Documentation of one common extreme cold benchmark temperature event t that was selected after
coordination with all Planning Coordinators within each of the identified zone(s).
Documentation that each benchmark temperature event considers no less than a 40-year period of
temperature data ending no more than five years prior to the time the benchmark temperature events were
selected.
Documentation that selected benchmark temperature events represented one of the 20 most extreme
temperature conditions based on the three-day rolling average of daily maximum (heat) or daily minimum
(cold) temperatures across the zone.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to TPL-008-1, R2
This section to be completed by the Compliance Enforcement Authority
(R2) Verify the entity identified all the zone(s) to which it belongs under Attachment 1.
(R2) Verify the selection, as coordinated with all Planning Coordinators within the zone, of one common
extreme heat benchmark temperature event for each of the entity’s identified zone(s) used for
completion of the Extreme Temperature Assessment.
(R2) Verify the selection, as coordinated with all Planning Coordinators within the zone, of one common
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extreme cold benchmark temperature event for each of the entity’s identified zone(s) used for
completion of the Extreme Temperature Assessment.
(Part 2.1.) Verify the selected benchmark temperature events considered no less than a 40-year period
of temperature data ending no more than five years prior to the time the benchmark temperature
events were selected
(Part 2.2.) Verify the selected benchmark temperature events represented one of the 20 most extreme
conditions based on the three-day rolling average of daily maximum (heat) or daily minimum (cold)
temperature across the zone.
(R2) Review processes for the coordination of Planning Coordinators within each of the entity’s
identified zone(s) to select the common extreme heat and cold benchmark temperature events.
Note to Auditor: The ERO will maintain a library of benchmark events to provide responsible entities access
to vetted benchmark temperature events that meet the criteria of Requirement R2. While selection of
events from the ERO’s provided library assures entities they are selecting valid events, Requirement R2 does
not preclude entities from collecting temperature data and identifying benchmark temperature events
through their own process. Entities that elect to develop their own benchmark temperature events are
responsible for ensuring the input temperature data and selected benchmark temperature events meet the
criteria of Requirement R2. Additionally, because Requirement R2 requires PCs within a zone to coordinate
in the selection of the benchmark temperature events, the process used to identify these events must be
agreeable to those PCs.
Auditor Notes:

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R3 Supporting Evidence and Documentation
R3.

Each Planning Coordinator shall coordinate with all Planning Coordinators within each of its zone(s) identified in
Requirement R2, to implement a process for developing benchmark planning cases for the Extreme
Temperature Assessment that represent the benchmark temperature events selected in Requirement R2 and
sensitivity cases to demonstrate the impact of changes to the basic assumptions used in the benchmark planning
cases. This process shall include the following: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
3.1. Selection of System models within the Long-Term Transmission Planning Horizon to form the basis for the
benchmark planning cases.
3.2. Forecasted seasonal and temperature dependent adjustments for Load, generation, Transmission, and
transfers within the zone.
3.3. Assumed seasonal and temperature dependent adjustments for Load, generation, Transmission, and
transfers in areas outside the zone, as needed.
3.4. Identification of changes to at least one of the following conditions for sensitivity cases: generation, real and
reactive forecasted Load, or transfers.

M3.

Each Planning Coordinator shall have dated evidence that it implemented a process for coordinating the
development of benchmark planning cases and sensitivity cases for the Extreme Temperature Assessment as
specified in Requirement R3.

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Documented and implemented process(es) for coordinating, with applicable Planning Coordinators identified
in Requirement R2, the development of benchmark planning cases and sensitivity cases for the Extreme
Temperature Assessment. The process(es) must demonstrate the following:
Selection of System models within the Long-Term Transmission Planning Horizon to form the basis for the
benchmark planning cases.
Forecasted seasonal and temperature dependent adjustments for Load, generation, Transmission, and
transfers within the zone.
Assumed seasonal and temperature dependent adjustments for Load, generation, Transmission, and
transfers in areas outside the zone, as needed.
Identification of changes to at least one of the following conditions for sensitivity cases: generation, real and
reactive forecasted Load, or transfers.

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Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to TPL-008-1, R3
This section to be completed by the Compliance Enforcement Authority
(R3) Verify implementation of process(es) for coordinating, with all applicable Planning Coordinators
within each of the entity’s zone(s) identified in Requirement R2, the development of benchmark
planning cases and sensitivity cases for the Extreme Temperature Assessment. Verify this process(es)
demonstrate the following:
(Part 3.1.) Selection of System models within the Long-Term Transmission Planning Horizon to form the
basis for the benchmark planning cases.
(Part 3.2.) Forecasted seasonal and temperature dependent adjustments for Load, generation,
Transmission, and transfers within the zone.
(Part 3.3.) Assumed seasonal and temperature dependent adjustments for Load, generation,
Transmission, and transfers in areas outside the zone, as needed.
(Part 3.4.) Identification of changes to at least one of the following conditions for sensitivity cases:
generation, real and reactive forecasted Load, or transfers.
Note to Auditor:
Auditor Notes:
R4 Supporting Evidence and Documentation
R4.

Each responsible entity, as identified in Requirement R1, shall use the coordination process developed in
Requirement R3 and data consistent with that provided in accordance with the MOD-032 standard,
supplemented by other sources as needed, to develop the following and establish category P0 as the normal
System condition in Table 1: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. One common extreme heat and one common extreme cold benchmark planning case.
4.2. One common extreme heat and one common extreme cold sensitivity case.

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M4.

Each responsible entity, as identified in Requirement R1, shall have dated evidence in either electronic or hard
copy format that it developed benchmark planning cases and sensitivity cases in accordance with Requirement
R4.

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Evidence of one common extreme heat and one common extreme cold benchmark planning case, showing
the coordination process developed in Requirement R3 was used and that data was consistent with that
provided in accordance with MOD-032 and that category P0 was established. .
Evidence of one common extreme heat and one common extreme cold sensitivity case, showing the
coordination process developed in Requirement R3 was used and that data was consistent with that provided
in accordance with MOD-032 . and that category P0 was established.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to TPL-008-1, R4
This section to be completed by the Compliance Enforcement Authority
(R4.) Verify that category P0, as the normal System condition in Table 1, was established.
(Part 4.1.) Verify that one common extreme heat and one common extreme cold benchmark planning
case was developed using the coordination process developed in Requirement R3 and with data
consistent with that provided in accordance with the MOD-032 standard.
(Part 4.2.) Verify that one common extreme heat and one common extreme cold sensitivity case was
developed using the coordination process developed in Requirement R3 and with data consistent with
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that provided in accordance with the MOD-032 standard.
Note to Auditor:
Auditor Notes:

R5 Supporting Evidence and Documentation
R5.

Each responsible entity, as identified in Requirement R1, shall have criteria for acceptable System steady state
voltage limits and post-Contingency voltage deviations for completing the Extreme Temperature Assessment.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

M5.

Each responsible entity, as identified in Requirement R1, shall provide dated evidence, such as electronic or hard
copies of the documentation, specifying the criteria for acceptable System steady state voltage limits and postContingency voltage deviations for completing the Extreme Temperature Assessment.

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Documentation specifying the criteria for acceptable System steady state voltage limits for completing the
Extreme Temperature Assessment.
Documentation specifying the criteria for acceptable post-Contingency voltage deviations for completing
the Extreme Temperature Assessment.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

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Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to TPL-008-1, R5
This section to be completed by the Compliance Enforcement Authority
Verify the entity has criteria for acceptable System steady state voltage limits for completing the
Extreme Temperature Assessment.
Verify the entity has criteria for acceptable post-Contingency voltage deviations for completing the
Extreme Temperature Assessment.
Note to Auditor: The establishment of these criteria allows auditors to compare the results of the Extreme
Temperature Assessment with the established criteria.
Auditor Notes:
R6 Supporting Evidence and Documentation
R6.

Each responsible entity, as identified in Requirement R1, shall define and document the criteria or methodology
to be used in the Extreme Temperature Assessment to identify instability, uncontrolled separation, or Cascading
within an Interconnection. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]

M6.

Each responsible entity, as identified in Requirement R1, shall provide dated evidence, such as electronic or hard
copies of documentation, specifying the criteria or methodology to be used in the Extreme Temperature
Assessment to identify instability, uncontrolled separation, or Cascading within an Interconnection in
accordance with Requirement R6.

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Documentation specifying the criteria or methodology used in the Extreme Temperature Assessment to
identify instability, uncontrolled separation, or Cascading within an Interconnection.

Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
NERC Reliability Standard Audit Worksheet
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RSAW Version: RSAW_TPL-008-1_2024_v1 Revision Date: November 2024 RSAW Template: RSAW2014R1.2
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File Name

Document Title

Revision
or
Version

Relevant
Page(s)
Document
or
Date
Section(s)

Description of Applicability
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to TPL-008-1, R6
This section to be completed by the Compliance Enforcement Authority
Verify the entity has documented criteria or methodology used within the Extreme Temperature
Assessment to identify instability, uncontrolled separation, or Cascading within an Interconnection.
Note to Auditor: The establishment of these criteria allows auditors to compare the results of the Extreme
Temperature Assessment with the established criteria.
Auditor Notes:

R7 Supporting Evidence and Documentation
R7.
Each responsible entity, as identified in Requirement R1, shall identify the Contingencies for each category in

Table 1 that are expected to produce more severe System impacts on its portion of the Bulk Electric System. The
rationale for those Contingencies selected for evaluation shall be available as supporting information. [Violation
Risk Factor: Medium] [Time Horizon: Long-term Planning]

M7.

Each responsible entity, as identified in Requirement R1, shall provide dated evidence, such as electronic or hard
copies of documentation, of the Contingencies for each category in Table 1 that are expected to produce more
severe System impacts on its portion of the Bulk Electric System along with supporting rationale.

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Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Documentation, including supporting rationale, of the Contingencies for each category in Table 1 that are
expected to produce more severe System impacts on your portion of the Bulk Electric System.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to TPL-008-1, R7
This section to be completed by the Compliance Enforcement Authority
Verify that the entity identified Contingencies for each category in Table 1 that are expected to produce
more severe System impacts for the entity’s portion of the Bulk Electric System.
Verify the supporting documentation and rationale for those Contingencies selected for evaluation by
the entity.
Note to Auditor: If feasible, all Contingencies listed in Table 1 should be considered for evaluation by the
responsible entity; however, the language affords flexibility in identifying the most impactful Contingencies.
As such, the responsible entity must identify, with supporting rationale, the Contingencies within each
category of Table 1 that are expected to produce more severe System impacts within its planning area . It is
noted that since the benchmark planning cases are developed from the extreme temperature benchmark
events, they already represent extreme System conditions and thus not all Contingencies from Reliability
Standard TPL-001-5.1 Table 1 are included in the TPL-008-1 Table 1 for assessment. The Events included in
TPL-008- 1 Table 1 represent the more likely Contingencies to occur.
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Auditor Notes:

R8 Supporting Evidence and Documentation
R8.
Each responsible entity, as identified in Requirement R1, shall complete steady state and transient stability

analyses in the Extreme Temperature Assessment using the Contingencies identified in Requirement R7, and
shall document the assumptions and results. Steady state and transient stability analyses shall be performed for
the following: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]

8.1. Benchmark planning cases developed in accordance with Requirement R4 Part 4.1.
8.2. Sensitivity cases developed in accordance with Requirement R4 Part 4.2.

M8.

Each responsible entity, as identified in Requirement R1, shall provide dated evidence, such as electronic or hard
copies of documentation, of the assumptions and results of the steady state and transient stability analyses
completed in the Extreme Temperature Assessment.

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Documentation of assumptions used for the development of steady state and transient stability analyses in
the Extreme Temperature Assessment.
Documentation of results of the steady state and transient stability analyses completed in the Extreme
Temperature Assessment.
Documentation that the Contingencies identified in Requirement R7 were used to complete the steady state
and transient stability analyses in the Extreme Temperature Assessment.
Documentation that steady state and transient stability analyses were performed for benchmark planning
cases developed in accordance with Requirement R4 Part 4.1.
Documentation that steady state and transient stability analyses were performed for sensitivity cases
developed in accordance with Requirement R4 Part 4.2.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.

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File Name

Document Title

Revision
or
Version

Relevant
Page(s)
Document
or
Date
Section(s)

Description of Applicability
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to TPL-008-1, R8
This section to be completed by the Compliance Enforcement Authority
(R8.) Verify the steady state and transient stability analyses were completed in the Extreme
Temperature Assessment, using the Contingencies identified in Requirement R7.
(R8.) Verify the documented assumptions and results of the steady state and transient analyses in the
Extreme Temperature Assessment.
(Part 8.1.) Verify the steady state and transient analyses were performed for the benchmark planning
cases developed in accordance with Requirement R4 Part 4.1.
(Part 8.2.) Verify the steady state and transient analyses were performed for the sensitivity cases
developed in accordance with Requirement R4 Part 4.2.
Note to Auditor:
Auditor Notes:

R9 Supporting Evidence and Documentation
R9.

Each responsible entity, as identified in Requirement R1, shall develop a Corrective Action Plan(s) when the
analysis of a benchmark planning case, in accordance with Requirement R8 Part 8.1, indicates its portion of the
Bulk Electric System is unable to meet performance requirements for category P0 or P1 in Table 1. For each
Corrective Action Plan, the responsible entity shall: [Violation Risk Factor: High] [Time Horizon: Long-term
Planning]
9.1. Document alternative(s) considered when Non-Consequential Load Loss is utilized as an element of a
Corrective Action Plan for a Table 1 P1 Contingency.
9.2. Be permitted to utilize Non-Consequential Load Loss as an interim solution, which normally is not permitted
for category P0 in Table 1 for situations that are beyond the control of the Planning Coordinator or Transmission
Planner that prevent the implementation of a Corrective Action Plan in the required timeframe, provided that
the responsible entity documents the situation causing the problem, alternatives evaluated, and takes actions to
resolve the situation.

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9.3. Make its Corrective Action Plan available to, and solicit feedback from, applicable regulatory authorities or
governing bodies responsible for retail electric service issues
9.4. Be permitted to have revisions to the Corrective Action Plan in subsequent Extreme Temperature
Assessments, provided that the planned Bulk Electric System shall continue to meet the performance
requirements of Table 1.

M9.

Each responsible entity, as identified in Requirement R1, shall provide dated evidence, such as electronic or hard
copies of documentation, of each Corrective Action Plan developed in accordance with Requirement R9 when
the analysis of a benchmark planning case indicates its portion of the Bulk Electric System is unable to meet
performance requirements for category P0 or P1 in Table 1. Evidence shall include documentation of
correspondence with applicable regulatory authorities or governing bodies responsible for retail electric service
issues and any revision history.

Registered Entity Response (Required):
Question: Were any Corrective Action Plans developed when the analysis of a benchmark planning case, in
accordance with Requirement R8 Part 8.1, indicated a portion of your Bulk Electric System was unable to
meet performance requirements for category P0 or P1 in Table 1? If Yes, provide a listing of the Corrective
Action Plans, including the start date and if it is still effective.
☐ Yes ☐ No
[Note: A separate spreadsheet or other document may be used. If so, provide the document reference below.]

Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Documentation of each Corrective Action Plan (CAP) developed when the analysis of a benchmark planning
case, in accordance with Requirement R8 Part 8.1, indicated a portion of the Bulk Electric System was
unable to meet performance requirements for category P0 or P1 in Table 1.
Documentation that each CAP developed in accordance with Requirement R9 addresses Part 9.1 through
Part 9.4.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document
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Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to TPL-008-1, R9
This section to be completed by the Compliance Enforcement Authority
(R9.) Verify a CAP was developed when analysis of a benchmark planning case, in accordance with
Requirement R8 Part 8.1, indicated the entity’s portion of the Bulk Electric System was unable to meet
performance requirements for Category P0 and P1.
(Part 9.1.) Verify each CAP documents the alternative(s) considered when Non-Consequential Load Loss
was utilized for a Table 1 P1 Contingency.
(Part 9.2.) If Non-Consequential Load Loss was utilized by the entity as an interim solution, verify the
situation(s) that was beyond the control of the Planning Coordinator or Transmission Planner.
(Part 9.2.) If Non-Consequential Load Loss was utilized by the entity as an interim solution, verify the
entity documented the situation causing the problem, evaluated alternatives and took action to resolve
the situation.
(Part 9.3.) Verify each CAP was made available to, and solicited feedback from, applicable regulatory
authorities or governing bodies responsible for retail electric service issues.
(Part 9.4.) Verify any revisions to CAP(s) in subsequent Extreme Temperature Assessments and verify
that the planned BES meets the performance requirements of Table 1.
Note to Auditor:
Auditor Notes:

R10 Supporting Evidence and Documentation
R10.

Each responsible entity, as identified in Requirement R1, shall evaluate and document possible actions designed
to reduce the likelihood or mitigate the consequences and adverse impacts of the event(s) if analyses conclude
there could be instability, uncontrolled separation, or Cascading within an Interconnection, for the following:
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
10.1. Table 1 P7 Contingencies in benchmark planning cases analyzed in accordance with Requirement R8 Part
8.1.
10.2. Categories P0, P1, and P7 in Table 1 in sensitivity cases analyzed in accordance with Requirement R8 Part
8.2.

M10. Each responsible entity, as identified in Requirement R1, shall provide dated evidence such as electronic or hard
copies of documentation that it evaluated and documented possible actions designed to reduce the likelihood
or mitigate the consequences and adverse impacts when the analyses conclude there could be instability,
uncontrolled separation, or Cascading within an Interconnection for Table 1 P7 Contingencies in benchmark
planning cases or categories P0, P1, or P7 in Table 1 in sensitivity cases.

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Registered Entity Response (Required):
Question: Did the analyses of any benchmark planning cases or sensitivity cases as described in
Requirement R10. Part 10.1. and Part 10.2. conclude there could be instability, uncontrolled separation, or
Cascading within an Interconnection? If Yes, provide a listing of theses analyses.
☐ Yes ☐ No
[Note: A separate spreadsheet or other document may be used. If so, provide the document reference below.]

Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Documented evaluation and possible actions designed to reduce the likelihood or mitigate the
consequences and adverse impacts of the event(s) if analyses concluded there could be instability,
uncontrolled separation, or Cascading within an Interconnection for Table 1 P7 Contingencies in benchmark
planning cases analyzed in accordance with Requirement R8 Part 8.1
Documented evaluation and possible actions designed to reduce the likelihood or mitigate the
consequences and adverse impacts of the event(s) if analyses concluded there could be instability,
uncontrolled separation, or Cascading within an Interconnection for Categories P0, P1, and P7 in Table 1 in
sensitivity cases analyzed in accordance with Requirement R8 Part 8.2.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to TPL-008-1, R10
NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-008-1_2024_v1 Revision Date: November 2024 RSAW Template: RSAW2014R1.2
19
Limited Disclosure

NERC Reliability Standard
Audit Worksheet

This section to be completed by the Compliance Enforcement Authority
(Part 10.1.) Verify the documented evaluation and possible actions designed to reduce the likelihood or
mitigate the consequences and adverse impacts of the event(s) if analyses concluded there could be
instability, uncontrolled separation, or Cascading within an Interconnection for Table 1 P7 Contingencies
in benchmark planning cases analyzed in accordance with Requirement R8 Part 8.1
(Part 10.2.) Verify the documented evaluation and possible actions designed to reduce the likelihood or
mitigate the consequences and adverse impacts of the event(s) if analyses concluded there could be
instability, uncontrolled separation, or Cascading within an Interconnection for Categories P0, P1, and
P7 in Table 1 in sensitivity cases analyzed in accordance with Requirement R8 Part 8.2.
Note to Auditor:
Auditor Notes:

R11 Supporting Evidence and Documentation
R11.

Each responsible entity, as identified in Requirement R1, shall provide its Extreme Temperature Assessment
results within 60 calendar days of a request to any functional entity that has a reliability related need and
submits a written request for the information. [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]

M11. .Each responsible entity, as identified in Requirement R1, shall provide dated evidence, such as email notices,

documentation of updated web pages, or postal receipts showing recipient, that it provided its Extreme
Temperature Assessment to any functional entity who has a reliability need within 60 calendar days of a written
request.

Registered Entity Response (Required):
Question: Was a written request for the Extreme Temperature Assessment received from any functional
entity who had a reliability need? If Yes, provide a listing of the date of request and associated functional
entity making the request.
☐ Yes ☐ No
[Note: A separate spreadsheet or other document may be used. If so, provide the document reference below.]

Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Documentation that the Extreme Temperature Assessment was provided within 60 calendar days of a written
request to any requesting functional entity who had a reliability need.
NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-008-1_2024_v1 Revision Date: November 2024 RSAW Template: RSAW2014R1.2
20
Limited Disclosure

NERC Reliability Standard
Audit Worksheet

Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to TPL-008-1, R11
This section to be completed by the Compliance Enforcement Authority
Verify that the Extreme Temperature Assessment results were provided to any written request, as
applicable, from any functional entity that has a reliability related need within 60 calendar days.
Note to Auditor:
Auditor Notes:

NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-008-1_2024_v1 Revision Date: November 2024 RSAW Template: RSAW2014R1.2
21
Limited Disclosure

NERC Reliability Standard
Audit Worksheet

Additional Information:
Reliability Standard PDF TO BE ADDED AFTER FERC APPROVAL
The full text of TPL-008-1 may be found on the NERC Web Site (www.nerc.com) under “Program Areas &
Departments”, “Reliability Standards.”
In addition to the Reliability Standard, there is an applicable Implementation Plan available on the NERC Web
Site.
In addition to the Reliability Standard, there is background information available on the NERC Web Site.
Capitalized terms in the Reliability Standard refer to terms in the NERC Glossary, which may be found on the
NERC Web Site.
Sampling Methodology
Sampling is essential for auditing compliance with NERC Reliability Standards since it is not always possible
or practical to test 100% of either the equipment, documentation, or both, associated with the full suite of
enforceable standards. The Sampling Methodology Guidelines and Criteria (see NERC website), or sample
guidelines, provided by the Electric Reliability Organization help to establish a minimum sample set for
monitoring and enforcement uses in audits of NERC Reliability Standards.
Regulatory Language
TO BE ADDED AFTER FERC APPROVAL

NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-008-1_2024_v1 Revision Date: November 2024 RSAW Template: RSAW2014R1.2
22
Limited Disclosure

NERC Reliability Standard
Audit Worksheet

Revision History for RSAW
Version

Date

1

12/1/2024

Reviewers
NERC Compliance
Assurance, Operations
and Planning
Compliance Task Force

Revision Description
New Document

i

Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These items are not
mandatory and other forms and types of evidence may be submitted at the entity’s discretion.

NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-008-1_2024_v1 Revision Date: November 2024 RSAW Template: RSAW2014R1.2
23
Limited Disclosure

Standards Announcement

Project 2023-07 Transmission Planning Performance
Requirements for Extreme Weather
Final Ballots Open through December 6, 2024
Now Available

Final ballots for TPL-008-1 – Transmission System Planning Performance Requirements for Extreme
Temperature Events and its implementation plan are open through 8 p.m. Eastern, Friday, December 6,
2024.
The Standards Committee approved waivers to the Standards Process Manual at their December 2023
meeting. These waivers were sought by NERC Standards for reduced formal comment and ballot periods
to assist the drafting teams in expediting the standards development process due to firm timeline
expectations set by FERC Order 896.
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 into the Standards Balloting and
Commenting System (SBS) and submit votes here.
•

Contact NERC IT support directly at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5
p.m. Eastern) for problems regarding accessing the SBS due to a forgotten password,
incorrect credential error messages, or system lock-out.

•

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 standard will be
submitted to the Board of Trustees for adoption and then filed with the appropriate regulatory
authorities.
For information on the Standards Development Process, refer to the Standard Processes Manual.

RELIABILITY | RESILIENCE | SECURITY

For more information or assistance, contact Senior Standards Developer, Jordan Mallory (via email) or at
404-479-7358.

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 2023-07 Transmission Planning Performance Requirements for Extreme Weather
Final Ballots | December 2024

2

NERC Balloting Tool (/)

Dashboard (/)

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS  
Ballot Name: 2023-07 Transmission Planning Performance Requirements for Extreme Weather TPL-008-1 FN 5 ST
Voting Start Date: 12/2/2024 11:10:07 AM
Voting End Date: 12/6/2024 8:00:00 PM
Ballot Type: ST
Ballot Activity: FN
Ballot Series: 5
Total # Votes: 264
Total Ballot Pool: 314
Quorum: 84.08
Quorum Established Date: 12/2/2024 12:50:35 PM
Weighted Segment Value: 75.43
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

89

1

46

0.73

17

0.27

0

15

11

Segment:
2

8

0.8

6

0.6

2

0.2

0

0

0

Segment:
3

68

1

39

0.796

10

0.204

0

10

9

Segment:
4

18

1

7

0.636

4

0.364

0

2

5

Segment:
5

76

1

29

0.659

15

0.341

0

14

18

Segment:
6

47

1

25

0.781

7

0.219

0

8

7

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

1

0

0

0

0

0

0

1

0

0

0

0

0

0

Segment

Segment: 0
0
0
0
9 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
© 2024

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:
10

7

0.7

7

0.7

0

0

0

0

0

Totals:

314

6.5

159

4.903

55

1.597

0

50

50

Segment

BALLOT POOL MEMBERS
Show

All

Segment

entries

Organization

Search:

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power,
Inc.

Hillary Creurer

Affirmative

N/A

1

Ameren - Ameren Services

Tamara Evey

None

N/A

1

American Transmission
Company, LLC

Amy Wilke

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Daniela
Atanasovski

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Jennifer Bray

Affirmative

N/A

1

Associated Electric
Cooperative, Inc.

Mark Riley

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Avista - Avista Corporation

Mike Magruder

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

Negative

N/A

1
BC Hydro and Power
Adrian Andreoiu
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Authority

Tim Kelley

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

Affirmative

N/A

1

Black Hills Corporation

Trevor Rombough

None

N/A

1

Bonneville Power
Administration

Kamala RogersHolliday

Affirmative

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Negative

N/A

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

None

N/A

1

Central Iowa Power
Cooperative

Kevin Lyons

Negative

N/A

1

City Utilities of Springfield,
Missouri

Michael Bowman

Negative

N/A

1

Colorado Springs Utilities

Corey Walker

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dairyland Power
Cooperative

Karrie Schuldt

Negative

N/A

1

Dominion - Dominion
Virginia Power

Steven Belle

Affirmative

N/A

1

Duke Energy

Katherine Street

Affirmative

N/A

1

Edison International Southern California Edison
Company

Robert Blackney

Affirmative

N/A

1

Entergy

Brian Lindsey

None

N/A

1

Evergy

Kevin Frick

Affirmative

N/A

1

Eversource Energy

Joshua London

Negative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

John Martinez

Affirmative

N/A

Negative

N/A

1
Georgia Transmission
Greg Davis
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Corporation

Hayden Maples

Stephen Stafford

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Glencoe Light and Power
Commission

Terry Volkmann

Negative

N/A

1

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Emma Halilovic

Lidija Efremova

Affirmative

N/A

1

Hydro-Quebec (HQ)

Nicolas Turcotte

Chantal Mazza

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Sean Steffensen

None

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Denise Sanchez

Affirmative

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Allie Gavin

Affirmative

N/A

1

JEA

Joseph McClung

Affirmative

N/A

1

KAMO Electric Cooperative

Micah Breedlove

Affirmative

N/A

1

Lakeland Electric

Larry Watt

None

N/A

1

Lincoln Electric System

Josh Johnson

Abstain

N/A

1

Long Island Power
Authority

Isidoro Behar

Affirmative

N/A

1

Los Angeles Department of
Water and Power

faranak sarbaz

Abstain

N/A

1

Lower Colorado River
Authority

Matt Lewis

Abstain

N/A

1

LS Power Transmission,
LLC

Jennifer
Richardson

Abstain

N/A

1

M and A Electric Power
Cooperative

William Price

Affirmative

N/A

1

Manitoba Hydro

Nazra Gladu

Affirmative

N/A

1

MEAG Power

David Weekley

Rebika Yitna

Abstain

N/A

1

Minnkota Power
Cooperative Inc.

Theresa Allard

Nikki CarsonMarquis

Affirmative

N/A

Abstain

N/A

1
Muscatine Power and
Andrew Kurriger
© 2024 - NERC Ver 4.2.1.0
Machine
Name:
ATLVPEROWEB01
Water

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Abstain

N/A

1

NB Power Corporation

Jeffrey Streifling

Abstain

N/A

1

Nebraska Public Power
District

Jamison Cawley

Negative

N/A

1

New York Power Authority

Daniel Valle

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Negative

N/A

1

NiSource - Northern
Indiana Public Service Co.

Alison Nickells

Negative

N/A

1

Northeast Missouri Electric
Power Cooperative

Brett Douglas

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

None

N/A

1

Oncor Electric Delivery

Byron Booker

Negative

N/A

1

Orlando Utilities
Commission

Aaron Staley

None

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Negative

N/A

1

Pacific Gas and Electric
Company

Marco Rios

Negative

N/A

1

Platte River Power
Authority

Marissa Archie

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Affirmative

N/A

1

Portland General Electric
Co.

Brooke Jockin

Abstain

N/A

Affirmative

N/A

1

PPL Electric Utilities
Michelle
Corporation
McCartney Longo
© 2024 - NERC Ver 4.2.1.0
Machine Name: ATLVPEROWEB01

Broc Bruton

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

PSEG - Public Service
Electric and Gas Co.

Karen Arnold

Affirmative

N/A

1

Public Utility District No. 1
of Chelan County

Diane E Landry

Negative

N/A

1

Public Utility District No. 1
of Snohomish County

Alyssia Rhoads

Affirmative

N/A

1

Public Utility District No. 2
of Grant County,
Washington

Joanne Anderson

Abstain

N/A

1

Sacramento Municipal
Utility District

Wei Shao

Tim Kelley

Affirmative

N/A

1

Salt River Project

Laura Somak

Israel Perez

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Abstain

N/A

1

SaskPower

Wayne
Guttormson

Abstain

N/A

1

Seminole Electric
Cooperative, Inc.

Kristine Ward

None

N/A

1

Sempra - San Diego Gas
and Electric

Mohamed Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Abstain

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

David Plumb

Negative

N/A

1

Tri-State G and T
Association, Inc.

Donna Wood

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Abstain

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Unisource - Tucson Electric
Power Co.

Jessica Cordero

Negative

N/A

1

VELCO -Vermont Electric
Power Company, Inc.

Randall Buswell

Abstain

N/A

1

Western Area Power
Administration

Ben Hammer

Affirmative

N/A

1

Xcel Energy, Inc.

Eric Barry

None

N/A

2

California ISO

Darcy O'Connell

Affirmative

N/A

2

Electric Reliability Council
of Texas, Inc.

Kennedy Meier

Negative

N/A

2

Independent Electricity
System Operator

Helen Lainis

Affirmative

N/A

2

ISO New England, Inc.

John Pearson

Affirmative

N/A

2

Midcontinent ISO, Inc.

Kirsten Rowley

Affirmative

N/A

2

New York Independent
System Operator

Gregory Campoli

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Thomas Foster

Elizabeth Davis

Affirmative

N/A

2

Southwest Power Pool, Inc.
(RTO)

Joshua Phillips

Shannon
Mickens

Negative

N/A

3

AEP

Leshel Hutchings

Affirmative

N/A

3

Ameren - Ameren Services

David Jendras Sr

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Jessica Lopez

Affirmative

N/A

3

Arkansas Electric
Cooperative Corporation

Ayslynn Mcavoy

Abstain

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

Lovita Griffin

Affirmative

N/A

3

Avista - Avista Corporation

Robert Follini

Affirmative

N/A

Negative

N/A

3
BC Hydro and Power
Ming Jiang
© 2024 - NERC Ver 4.2.1.0
Machine
Name:
ATLVPEROWEB01
Authority

Keith Jonassen

Danielle Moskop

Segment

Organization

Voter

3

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Joseph Amato

3

Black Hills Corporation

Josh Combs

3

Bonneville Power
Administration

Ron Sporseen

3

Buckeye Power, Inc.

Tom Schmidt

3

Central Electric Power
Cooperative (Missouri)

3

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Affirmative

N/A

Affirmative

N/A

None

N/A

Adam Weber

Affirmative

N/A

City Utilities of Springfield,
Missouri

Jessica Morrissey

Negative

N/A

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

None

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Lincoln Burton

Affirmative

N/A

3

Dominion - Dominion
Virginia Power

Victoria Crider

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Marvin Johnson

Abstain

N/A

3

Duke Energy - Florida
Power Corporation

Marcelo Pesantez

Affirmative

N/A

3

Edison International Southern California Edison
Company

Romel Aquino

Affirmative

N/A

3

Entergy

James Keele

None

N/A

3

Evergy

Marcus Moor

Affirmative

N/A

3

Eversource Energy

Vicki O'Leary

Negative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Affirmative

N/A

None

N/A

3
Georgia System
Scott McGough
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Operations Corporation

Carly Miller

Ryan Strom

Hayden Maples

Segment

Organization

Voter

3

Great River Energy

Michael Brytowski

3

Imperial Irrigation District

George Kirschner

3

JEA

3

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Affirmative

N/A

Marilyn Williams

Affirmative

N/A

Lakeland Electric

Steven Marshall

None

N/A

3

Lincoln Electric System

Sam Christensen

Abstain

N/A

3

Los Angeles Department of
Water and Power

Fausto Serratos

Abstain

N/A

3

M and A Electric Power
Cooperative

Gary Dollins

Affirmative

N/A

3

Manitoba Hydro

Mike Smith

Affirmative

N/A

3

MEAG Power

Roger Brand

Abstain

N/A

3

MGE Energy - Madison
Gas and Electric Co.

Benjamin Widder

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Abstain

N/A

3

National Grid USA

Brian Shanahan

Abstain

N/A

3

Nebraska Public Power
District

Tony Eddleman

Negative

N/A

3

New York Power Authority

Richard Machado

Affirmative

N/A

3

NextEra Energy - Florida
Power and Light Co.

Karen Demos

Negative

N/A

3

NiSource - Northern
Indiana Public Service Co.

Steven Taddeucci

Negative

N/A

3

Northern California Power
Agency

Michael Whitney

None

N/A

3

NW Electric Power
Cooperative, Inc.

Heath Henry

Affirmative

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

Negative

N/A

3

Omaha Public Power
David Heins
District
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Denise Sanchez

Rebika Yitna

Segment

Organization

Voter

3

OTP - Otter Tail Power
Company

Wendi Olson

3

Pacific Gas and Electric
Company

Sandra Ellis

3

Platte River Power
Authority

3

Designated
Proxy

Ballot

NERC
Memo

None

N/A

Negative

N/A

Richard Kiess

Affirmative

N/A

PNM Resources - Public
Service Company of New
Mexico

Amy
Wesselkamper

Affirmative

N/A

3

Portland General Electric
Co.

Mayra Franco

Abstain

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

Christopher
Murphy

Affirmative

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Negative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Tim Kelley

Affirmative

N/A

3

Salt River Project

Mathew Weber

Israel Perez

Affirmative

N/A

3

Santee Cooper

Vicky Budreau

Abstain

N/A

3

Seminole Electric
Cooperative, Inc.

Usama Tahir

None

N/A

3

Sempra - San Diego Gas
and Electric

Bryan Bennett

Affirmative

N/A

3

Sho-Me Power Electric
Cooperative

Jarrod Murdaugh

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

Southern Indiana Gas and
Electric Co.

Ryan Snyder

Abstain

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Bob Cardle

Segment

Organization

Voter

3

Tacoma Public Utilities
(Tacoma, WA)

John Nierenberg

3

Tennessee Valley Authority

3

Designated
Proxy

NERC
Memo

Affirmative

N/A

Ian Grant

Negative

N/A

Tri-State G and T
Association, Inc.

Amanda Skubal

Affirmative

N/A

3

Xcel Energy, Inc.

Nicholas Friebel

None

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Negative

N/A

4

Arkansas Electric
Cooperative Corporation

Jenni Sudduth

None

N/A

4

Austin Energy

Tony Hua

Affirmative

N/A

4

Buckeye Power, Inc.

Jason Procuniar

None

N/A

4

City Utilities of Springfield,
Missouri

Jerry Bradshaw

Negative

N/A

4

CMS Energy - Consumers
Energy Company

Aric Root

None

N/A

4

DTE Energy

Patricia Ireland

Abstain

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

Affirmative

N/A

4

Georgia System
Operations Corporation

Katrina Lyons

Negative

N/A

4

North Carolina Electric
Membership Corporation

Richard McCall

Scott Brame

Negative

N/A

4

Northern California Power
Agency

Marty Hostler

Mason Jones

None

N/A

4

Public Utility District No. 1
of Snohomish County

John D.
Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Abstain

N/A

4

Sacramento Municipal
Utility District

Foung Mua

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Ballot

Joseph Gatten

Ryan Strom

Tim Kelley

Segment

Organization

Voter

4

Seminole Electric
Cooperative, Inc.

George Pino

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

4

Utility Services, Inc.

4

Designated
Proxy

Ballot

NERC
Memo

None

N/A

Affirmative

N/A

Carver Powers

Affirmative

N/A

Western Power Pool

Kevin Conway

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

AES - AES Corporation

Ruchi Shah

None

N/A

5

Ameren - Ameren Missouri

Sam Dwyer

None

N/A

5

APS - Arizona Public
Service Co.

Andrew Smith

Affirmative

N/A

5

Associated Electric
Cooperative, Inc.

Chuck Booth

None

N/A

5

Austin Energy

Michael Dillard

Affirmative

N/A

5

Avista - Avista Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Christine
Jennings

Negative

N/A

5

Berkshire Hathaway - NV
Energy

Dwanique Spiller

Affirmative

N/A

5

Black Hills Corporation

Sheila Suurmeier

Affirmative

N/A

5

Bonneville Power
Administration

Milli Chennell

Affirmative

N/A

5

Buckeye Power, Inc.

Kevin Zemanek

None

N/A

5

California Department of
Water Resources

ASM Mostafa

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

CMS Energy - Consumers
Energy Company

David Greyerbiehl

None

N/A

5

Colorado Springs Utilities

Jeffrey Icke

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Con Ed - Consolidated
Edison Co. of New York

Michelle Pagano

Affirmative

N/A

5

Constellation

Alison MacKellar

Abstain

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

Dairyland Power
Cooperative

Tommy Drea

Negative

N/A

5

Dominion - Dominion
Resources, Inc.

Barbara Marion

Affirmative

N/A

5

DTE Energy - Detroit
Edison Company

Mohamad
Elhusseini

Abstain

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California Edison
Company

Selene Willis

Affirmative

N/A

5

Entergy - Entergy Services,
Inc.

Gail Golden

None

N/A

5

Evergy

Jeremy Harris

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Corporation

Matthew Augustin

Affirmative

N/A

5

Florida Municipal Power
Agency

Chris Gowder

LaKenya
Vannorman

None

N/A

5

Great River Energy

Jacalynn Bentz

Joseph Knight

None

N/A

5

Greybeard Compliance
Services, LLC

Mike Gabriel

Abstain

N/A

5

Grid Strategies LLC

Michael Goggin

None

N/A

5

Hydro-Quebec (HQ)

Junji Yamaguchi

Chantal Mazza

Affirmative

N/A

5

Imperial Irrigation District

Tino Zaragoza

Denise Sanchez

Affirmative

N/A

5

Invenergy LLC

Rhonda Jones

None

N/A

5

JEA

John Babik

Affirmative

N/A

5

Lincoln Electric System

Brittany Millard

Abstain

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Los Angeles Department of
Water and Power

Robert Kerrigan

Abstain

N/A

5

Lower Colorado River
Authority

Teresa Krabe

Abstain

N/A

5

LS Power Development,
LLC

C. A. Campbell

None

N/A

5

Manitoba Hydro

Kristy-Lee Young

None

N/A

5

Muscatine Power and
Water

Chance Back

Abstain

N/A

5

National Grid USA

Robin Berry

Abstain

N/A

5

NB Power Corporation New Brunswick Power
Transmission Corporation

Erin Wilson

Abstain

N/A

5

Nebraska Public Power
District

Ronald Bender

Negative

N/A

5

New York Power Authority

Zahid Qayyum

Affirmative

N/A

5

NextEra Energy

Richard Vendetti

Negative

N/A

5

NiSource - Northern
Indiana Public Service Co.

Kathryn Tackett

Negative

N/A

5

North Carolina Electric
Membership Corporation

Reid Cashion

Negative

N/A

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Negative

N/A

5

Oglethorpe Power
Corporation

Donna Johnson

Negative

N/A

5

Omaha Public Power
District

Kayleigh
Wilkerson

Negative

N/A

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Affirmative

N/A

5

Orlando Utilities
Commission

Dania Colon

Affirmative

N/A

Negative

N/A

5

OTP - Otter Tail Power
Stacy Wahlund
Company
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Helen Zhao

Kevin Schawang

Scott Brame

Segment

Organization

Voter

5

Pacific Gas and Electric
Company

Tyler Brun

5

Pattern Operators LP

5

Designated
Proxy

NERC
Memo

Negative

N/A

George E Brown

Negative

N/A

Platte River Power
Authority

Jon Osell

Affirmative

N/A

5

Portland General Electric
Co.

Ryan Olson

None

N/A

5

PSEG Nuclear LLC

Tim Kucey

None

N/A

5

Public Utility District No. 1
of Chelan County

Rebecca Zahler

Negative

N/A

5

Public Utility District No. 1
of Snohomish County

Becky Burden

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Loren Harbachuk

None

N/A

5

Sacramento Municipal
Utility District

Ryder Couch

Tim Kelley

Affirmative

N/A

5

Salt River Project

Thomas Johnson

Israel Perez

Affirmative

N/A

5

Santee Cooper

Carey Salisbury

Abstain

N/A

5

Seminole Electric
Cooperative, Inc.

Melanie Wong

None

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

Leslie Burke

Affirmative

N/A

5

Southern Indiana Gas and
Electric Co.

Larry Rogers

Abstain

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

Talen Generation, LLC

Donald Lock

Negative

N/A

Affirmative

N/A

5

Tallahassee Electric (City of
Karen Weaver
Tallahassee, FL)
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Bob Cardle

Ballot

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Tennessee Valley Authority

Darren Boehm

Negative

N/A

5

Tri-State G and T
Association, Inc.

Sergio Banuelos

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Kalidass

Abstain

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Abstain

N/A

6

AEP

Mathew Miller

Affirmative

N/A

6

Ameren - Ameren Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Marcus Bortman

Affirmative

N/A

6

Associated Electric
Cooperative, Inc.

Brian Ackermann

Affirmative

N/A

6

Austin Energy

Imane Mrini

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Lindsay Wickizer

None

N/A

6

Black Hills Corporation

Rachel Schuldt

Affirmative

N/A

6

Bonneville Power
Administration

Tanner Brier

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Negative

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Jason Chandler

Affirmative

N/A

6

Constellation

Kimberly Turco

Abstain

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Affirmative

N/A

6

Duke Energy

John Sturgeon

Affirmative

N/A

6

Edison International Southern California Edison
Company

Stephanie Kenny

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Evergy

Tiffany Lake

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

FirstEnergy - FirstEnergy
Corporation

Stacey Sheehan

Affirmative

N/A

6

Great River Energy

Brian Meloy

Negative

N/A

6

Imperial Irrigation District

Diana Torres

Affirmative

N/A

6

Lakeland Electric

Paul Shipps

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department of
Water and Power

Anton Vu

Abstain

N/A

6

Manitoba Hydro

Brandin Stoesz

None

N/A

6

Muscatine Power and
Water

Nicholas Burns

Abstain

N/A

6

New York Power Authority

Shelly Dineen

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

Negative

N/A

6

NiSource - Northern
Indiana Public Service Co.

Rebecca Blair

Negative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

NRG - NRG Energy, Inc.

Martin Sidor

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Ashley F Stringer

Affirmative

N/A

6

Omaha Public Power
District

Shonda McCain

Negative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Stefanie Burke

None

N/A

6

Powerex Corporation

Raj Hundal

Negative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

None

N/A

6
PSEG - PSEG Energy
Laura Wu
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Resources and Trade LLC

Denise Sanchez

Segment

Organization

Voter

6

Public Utility District No. 1
of Chelan County

Tamarra Hardie

6

Sacramento Municipal
Utility District

Charles Norton

6

Salt River Project

Timothy Singh

6

Santee Cooper

6

Designated
Proxy

Ballot

NERC
Memo

Negative

N/A

Tim Kelley

Affirmative

N/A

Israel Perez

Affirmative

N/A

Marty Watson

Abstain

N/A

Seminole Electric
Cooperative, Inc.

Bret Galbraith

None

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation and Energy
Marketing

Matthew O'neal

Affirmative

N/A

6

Southern Indiana Gas and
Electric Co.

Kati Barr

Abstain

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

Affirmative

N/A

6

Western Area Power
Administration

Jennifer Neville

Affirmative

N/A

6

Xcel Energy, Inc.

Steve Szablya

None

N/A

8

Florida Reliability
Coordinating Council –
Member Services Division

Vince Ordax

Abstain

N/A

10

Midwest Reliability
Organization

Mark Flanary

Affirmative

N/A

10

New York State Reliability
Council

Wesley Yeomans

Affirmative

N/A

10

Northeast Power
Coordinating Council

Gerry Dunbar

Affirmative

N/A

10

ReliabilityFirst

Tremayne Brown

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
10
Texas Reliability Entity, Inc.
Rachel Coyne

Affirmative

N/A

Jennie Wike

Greg Sorenson

Segment
10

Organization
Western Electricity
Coordinating Council

Voter
Steven Rueckert

Designated
Proxy

Affirmative

Previous
Showing 1 to 314 of 314 entries

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Memo

Ballot

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1

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BALLOT RESULTS  
Ballot Name: 2023-07 Transmission Planning Performance Requirements for Extreme Weather Implementation Plan FN 5
OT
Voting Start Date: 12/2/2024 11:11:09 AM
Voting End Date: 12/6/2024 8:00:00 PM
Ballot Type: OT
Ballot Activity: FN
Ballot Series: 5
Total # Votes: 264
Total Ballot Pool: 314
Quorum: 84.08
Quorum Established Date: 12/2/2024 12:50:41 PM
Weighted Segment Value: 79.38
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

89

1

49

0.79

13

0.21

0

16

11

Segment:
2

8

0.8

7

0.7

1

0.1

0

0

0

Segment:
3

68

1

41

0.837

8

0.163

0

10

9

Segment:
4

18

1

7

0.636

4

0.364

0

2

5

Segment:
5

76

1

31

0.705

13

0.295

0

14

18

Segment:
6

47

1

26

0.813

6

0.188

0

8

7

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

1

0

0

0

0

0

0

1

0

Segment

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

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:
9

0

0

0

0

0

0

0

0

0

Segment:
10

7

0.6

6

0.6

0

0

0

1

0

Totals:

314

6.4

167

5.08

45

1.32

0

52

50

Segment

BALLOT POOL MEMBERS
Show

All

Segment

entries

Organization

Search:

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power,
Inc.

Hillary Creurer

Affirmative

N/A

1

Ameren - Ameren Services

Tamara Evey

None

N/A

1

American Transmission
Company, LLC

Amy Wilke

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Daniela
Atanasovski

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Jennifer Bray

Affirmative

N/A

1

Associated Electric
Cooperative, Inc.

Mark Riley

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Avista - Avista Corporation

Mike Magruder

Affirmative

N/A

Affirmative

N/A

1
Balancing Authority of
Kevin Smith
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Northern California

Tim Kelley

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

BC Hydro and Power
Authority

Adrian Andreoiu

Negative

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

Affirmative

N/A

1

Black Hills Corporation

Trevor Rombough

None

N/A

1

Bonneville Power
Administration

Kamala RogersHolliday

Affirmative

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Negative

N/A

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

None

N/A

1

Central Iowa Power
Cooperative

Kevin Lyons

Negative

N/A

1

City Utilities of Springfield,
Missouri

Michael Bowman

Negative

N/A

1

Colorado Springs Utilities

Corey Walker

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dairyland Power
Cooperative

Karrie Schuldt

Negative

N/A

1

Dominion - Dominion
Virginia Power

Steven Belle

Affirmative

N/A

1

Duke Energy

Katherine Street

Affirmative

N/A

1

Edison International Southern California Edison
Company

Robert Blackney

Affirmative

N/A

1

Entergy

Brian Lindsey

None

N/A

1

Evergy

Kevin Frick

Affirmative

N/A

1

Eversource Energy

Joshua London

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1
FirstEnergy - FirstEnergy
John Martinez
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Corporation

Affirmative

N/A

Hayden Maples

Segment

Organization

Voter

1

Georgia Transmission
Corporation

Greg Davis

1

Glencoe Light and Power
Commission

1

Designated
Proxy

NERC
Memo

Affirmative

N/A

Terry Volkmann

Negative

N/A

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Emma Halilovic

Lidija Efremova

Affirmative

N/A

1

Hydro-Quebec (HQ)

Nicolas Turcotte

Chantal Mazza

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Sean Steffensen

None

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Denise Sanchez

Affirmative

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Allie Gavin

Affirmative

N/A

1

JEA

Joseph McClung

Affirmative

N/A

1

KAMO Electric Cooperative

Micah Breedlove

Affirmative

N/A

1

Lakeland Electric

Larry Watt

None

N/A

1

Lincoln Electric System

Josh Johnson

Abstain

N/A

1

Long Island Power
Authority

Isidoro Behar

Affirmative

N/A

1

Los Angeles Department of
Water and Power

faranak sarbaz

Abstain

N/A

1

Lower Colorado River
Authority

Matt Lewis

Abstain

N/A

1

LS Power Transmission,
LLC

Jennifer
Richardson

Abstain

N/A

1

M and A Electric Power
Cooperative

William Price

Affirmative

N/A

1

Manitoba Hydro

Nazra Gladu

Affirmative

N/A

1

MEAG Power

David Weekley

Rebika Yitna

Abstain

N/A

Nikki CarsonMarquis

Affirmative

N/A

1
Minnkota Power
Theresa Allard
© 2024 - NERC Ver 4.2.1.0
Machine
Name:
ATLVPEROWEB01
Cooperative Inc.

Stephen Stafford

Ballot

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Muscatine Power and
Water

Andrew Kurriger

Abstain

N/A

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Abstain

N/A

1

NB Power Corporation

Jeffrey Streifling

Abstain

N/A

1

Nebraska Public Power
District

Jamison Cawley

Negative

N/A

1

New York Power Authority

Daniel Valle

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Negative

N/A

1

NiSource - Northern
Indiana Public Service Co.

Alison Nickells

Negative

N/A

1

Northeast Missouri Electric
Power Cooperative

Brett Douglas

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

None

N/A

1

Oncor Electric Delivery

Byron Booker

Abstain

N/A

1

Orlando Utilities
Commission

Aaron Staley

None

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Negative

N/A

1

Pacific Gas and Electric
Company

Marco Rios

Negative

N/A

1

Platte River Power
Authority

Marissa Archie

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Affirmative

N/A

Abstain

N/A

1

Portland General Electric
Brooke Jockin
Co. Machine Name: ATLVPEROWEB01
© 2024 - NERC Ver 4.2.1.0

Broc Bruton

Bob Cardle

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

PPL Electric Utilities
Corporation

Michelle
McCartney Longo

Affirmative

N/A

1

PSEG - Public Service
Electric and Gas Co.

Karen Arnold

Affirmative

N/A

1

Public Utility District No. 1
of Chelan County

Diane E Landry

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Alyssia Rhoads

Affirmative

N/A

1

Public Utility District No. 2
of Grant County,
Washington

Joanne Anderson

Abstain

N/A

1

Sacramento Municipal
Utility District

Wei Shao

Tim Kelley

Affirmative

N/A

1

Salt River Project

Laura Somak

Israel Perez

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Abstain

N/A

1

SaskPower

Wayne
Guttormson

Abstain

N/A

1

Seminole Electric
Cooperative, Inc.

Kristine Ward

None

N/A

1

Sempra - San Diego Gas
and Electric

Mohamed Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Abstain

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

David Plumb

Negative

N/A

1

Tri-State G and T
Association, Inc.

Donna Wood

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

U.S. Bureau of
Reclamation

Richard Jackson

Abstain

N/A

1

Unisource - Tucson Electric
Power Co.

Jessica Cordero

Negative

N/A

1

VELCO -Vermont Electric
Power Company, Inc.

Randall Buswell

Abstain

N/A

1

Western Area Power
Administration

Ben Hammer

Affirmative

N/A

1

Xcel Energy, Inc.

Eric Barry

None

N/A

2

California ISO

Darcy O'Connell

Affirmative

N/A

2

Electric Reliability Council
of Texas, Inc.

Kennedy Meier

Affirmative

N/A

2

Independent Electricity
System Operator

Helen Lainis

Affirmative

N/A

2

ISO New England, Inc.

John Pearson

Affirmative

N/A

2

Midcontinent ISO, Inc.

Kirsten Rowley

Affirmative

N/A

2

New York Independent
System Operator

Gregory Campoli

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Thomas Foster

Elizabeth Davis

Affirmative

N/A

2

Southwest Power Pool, Inc.
(RTO)

Joshua Phillips

Shannon
Mickens

Negative

N/A

3

AEP

Leshel Hutchings

Affirmative

N/A

3

Ameren - Ameren Services

David Jendras Sr

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Jessica Lopez

Affirmative

N/A

3

Arkansas Electric
Cooperative Corporation

Ayslynn Mcavoy

Abstain

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

Lovita Griffin

Affirmative

N/A

© 2024
Name: ATLVPEROWEB01
3 - NERC Ver 4.2.1.0
Avista Machine
- Avista Corporation
Robert Follini

Affirmative

N/A

Keith Jonassen

Danielle Moskop

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

BC Hydro and Power
Authority

Ming Jiang

Negative

N/A

3

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Joseph Amato

Affirmative

N/A

3

Black Hills Corporation

Josh Combs

Affirmative

N/A

3

Bonneville Power
Administration

Ron Sporseen

Affirmative

N/A

3

Buckeye Power, Inc.

Tom Schmidt

None

N/A

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Affirmative

N/A

3

City Utilities of Springfield,
Missouri

Jessica Morrissey

Negative

N/A

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

None

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Lincoln Burton

Affirmative

N/A

3

Dominion - Dominion
Virginia Power

Victoria Crider

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Marvin Johnson

Abstain

N/A

3

Duke Energy - Florida
Power Corporation

Marcelo Pesantez

Affirmative

N/A

3

Edison International Southern California Edison
Company

Romel Aquino

Affirmative

N/A

3

Entergy

James Keele

None

N/A

3

Evergy

Marcus Moor

Affirmative

N/A

3

Eversource Energy

Vicki O'Leary

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

Affirmative

N/A

3
FirstEnergy - FirstEnergy
Aaron
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Corporation
Ghodooshim

Carly Miller

Ryan Strom

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Georgia System
Operations Corporation

Scott McGough

None

N/A

3

Great River Energy

Michael Brytowski

Affirmative

N/A

3

Imperial Irrigation District

George Kirschner

Affirmative

N/A

3

JEA

Marilyn Williams

Affirmative

N/A

3

Lakeland Electric

Steven Marshall

None

N/A

3

Lincoln Electric System

Sam Christensen

Abstain

N/A

3

Los Angeles Department of
Water and Power

Fausto Serratos

Abstain

N/A

3

M and A Electric Power
Cooperative

Gary Dollins

Affirmative

N/A

3

Manitoba Hydro

Mike Smith

Affirmative

N/A

3

MEAG Power

Roger Brand

Abstain

N/A

3

MGE Energy - Madison
Gas and Electric Co.

Benjamin Widder

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Abstain

N/A

3

National Grid USA

Brian Shanahan

Abstain

N/A

3

Nebraska Public Power
District

Tony Eddleman

Negative

N/A

3

New York Power Authority

Richard Machado

Affirmative

N/A

3

NextEra Energy - Florida
Power and Light Co.

Karen Demos

Negative

N/A

3

NiSource - Northern
Indiana Public Service Co.

Steven Taddeucci

Negative

N/A

3

Northern California Power
Agency

Michael Whitney

None

N/A

3

NW Electric Power
Cooperative, Inc.

Heath Henry

Affirmative

N/A

Affirmative

N/A

3

OGE Energy - Oklahoma
Donald Hargrove
Gas and Electric Co.
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Denise Sanchez

Rebika Yitna

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Omaha Public Power
District

David Heins

Negative

N/A

3

OTP - Otter Tail Power
Company

Wendi Olson

None

N/A

3

Pacific Gas and Electric
Company

Sandra Ellis

Negative

N/A

3

Platte River Power
Authority

Richard Kiess

Affirmative

N/A

3

PNM Resources - Public
Service Company of New
Mexico

Amy
Wesselkamper

Affirmative

N/A

3

Portland General Electric
Co.

Mayra Franco

Abstain

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

Christopher
Murphy

Affirmative

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Tim Kelley

Affirmative

N/A

3

Salt River Project

Mathew Weber

Israel Perez

Affirmative

N/A

3

Santee Cooper

Vicky Budreau

Abstain

N/A

3

Seminole Electric
Cooperative, Inc.

Usama Tahir

None

N/A

3

Sempra - San Diego Gas
and Electric

Bryan Bennett

Affirmative

N/A

3

Sho-Me Power Electric
Cooperative

Jarrod Murdaugh

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

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Bob Cardle

Segment

Organization

Voter

3

Southern Indiana Gas and
Electric Co.

Ryan Snyder

3

Tacoma Public Utilities
(Tacoma, WA)

John Nierenberg

3

Tennessee Valley Authority

3

Designated
Proxy

Ballot

NERC
Memo

Abstain

N/A

Affirmative

N/A

Ian Grant

Negative

N/A

Tri-State G and T
Association, Inc.

Amanda Skubal

Affirmative

N/A

3

Xcel Energy, Inc.

Nicholas Friebel

None

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Negative

N/A

4

Arkansas Electric
Cooperative Corporation

Jenni Sudduth

None

N/A

4

Austin Energy

Tony Hua

Affirmative

N/A

4

Buckeye Power, Inc.

Jason Procuniar

None

N/A

4

City Utilities of Springfield,
Missouri

Jerry Bradshaw

Negative

N/A

4

CMS Energy - Consumers
Energy Company

Aric Root

None

N/A

4

DTE Energy

Patricia Ireland

Abstain

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

Affirmative

N/A

4

Georgia System
Operations Corporation

Katrina Lyons

Negative

N/A

4

North Carolina Electric
Membership Corporation

Richard McCall

Scott Brame

Negative

N/A

4

Northern California Power
Agency

Marty Hostler

Mason Jones

None

N/A

4

Public Utility District No. 1
of Snohomish County

John D.
Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Abstain

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Jennie Wike

Joseph Gatten

Ryan Strom

Segment

Organization

Voter

4

Sacramento Municipal
Utility District

Foung Mua

4

Seminole Electric
Cooperative, Inc.

George Pino

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

4

Utility Services, Inc.

4

Designated
Proxy

NERC
Memo

Affirmative

N/A

None

N/A

Affirmative

N/A

Carver Powers

Affirmative

N/A

Western Power Pool

Kevin Conway

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

AES - AES Corporation

Ruchi Shah

None

N/A

5

Ameren - Ameren Missouri

Sam Dwyer

None

N/A

5

APS - Arizona Public
Service Co.

Andrew Smith

Affirmative

N/A

5

Associated Electric
Cooperative, Inc.

Chuck Booth

None

N/A

5

Austin Energy

Michael Dillard

Affirmative

N/A

5

Avista - Avista Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Christine
Jennings

Negative

N/A

5

Berkshire Hathaway - NV
Energy

Dwanique Spiller

Affirmative

N/A

5

Black Hills Corporation

Sheila Suurmeier

Affirmative

N/A

5

Bonneville Power
Administration

Milli Chennell

Affirmative

N/A

5

Buckeye Power, Inc.

Kevin Zemanek

None

N/A

5

California Department of
Water Resources

ASM Mostafa

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

None

N/A

5

CMS Energy - Consumers
David Greyerbiehl
Energy Company
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Tim Kelley

Ballot

Jennie Wike

Ryan Strom

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Colorado Springs Utilities

Jeffrey Icke

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

Michelle Pagano

Affirmative

N/A

5

Constellation

Alison MacKellar

Abstain

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

Dairyland Power
Cooperative

Tommy Drea

Negative

N/A

5

Dominion - Dominion
Resources, Inc.

Barbara Marion

Affirmative

N/A

5

DTE Energy - Detroit
Edison Company

Mohamad
Elhusseini

Abstain

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California Edison
Company

Selene Willis

Affirmative

N/A

5

Entergy - Entergy Services,
Inc.

Gail Golden

None

N/A

5

Evergy

Jeremy Harris

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Corporation

Matthew Augustin

Affirmative

N/A

5

Florida Municipal Power
Agency

Chris Gowder

LaKenya
Vannorman

None

N/A

5

Great River Energy

Jacalynn Bentz

Joseph Knight

None

N/A

5

Greybeard Compliance
Services, LLC

Mike Gabriel

Abstain

N/A

5

Grid Strategies LLC

Michael Goggin

None

N/A

5

Hydro-Quebec (HQ)

Junji Yamaguchi

Chantal Mazza

Affirmative

N/A

5

Imperial Irrigation District

Tino Zaragoza

Denise Sanchez

Affirmative

N/A

5

Invenergy LLC

Rhonda Jones

None

N/A

5

JEA

John Babik

Affirmative

N/A

Abstain

N/A

© 2024
5 - NERC Ver 4.2.1.0
LincolnMachine
Electric Name:
SystemATLVPEROWEB01
Brittany Millard

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Los Angeles Department of
Water and Power

Robert Kerrigan

Abstain

N/A

5

Lower Colorado River
Authority

Teresa Krabe

Abstain

N/A

5

LS Power Development,
LLC

C. A. Campbell

None

N/A

5

Manitoba Hydro

Kristy-Lee Young

None

N/A

5

Muscatine Power and
Water

Chance Back

Abstain

N/A

5

National Grid USA

Robin Berry

Abstain

N/A

5

NB Power Corporation New Brunswick Power
Transmission Corporation

Erin Wilson

Abstain

N/A

5

Nebraska Public Power
District

Ronald Bender

Negative

N/A

5

New York Power Authority

Zahid Qayyum

Affirmative

N/A

5

NextEra Energy

Richard Vendetti

Negative

N/A

5

NiSource - Northern
Indiana Public Service Co.

Kathryn Tackett

Negative

N/A

5

North Carolina Electric
Membership Corporation

Reid Cashion

Negative

N/A

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Negative

N/A

5

Oglethorpe Power
Corporation

Donna Johnson

Negative

N/A

5

Omaha Public Power
District

Kayleigh
Wilkerson

Negative

N/A

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Affirmative

N/A

5

Orlando Utilities
Commission

Dania Colon

Affirmative

N/A

Negative

N/A

5

OTP - Otter Tail Power
Stacy Wahlund
Company
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Helen Zhao

Kevin Schawang

Scott Brame

Segment

Organization

Voter

5

Pacific Gas and Electric
Company

Tyler Brun

5

Pattern Operators LP

5

Designated
Proxy

NERC
Memo

Negative

N/A

George E Brown

Negative

N/A

Platte River Power
Authority

Jon Osell

Affirmative

N/A

5

Portland General Electric
Co.

Ryan Olson

None

N/A

5

PSEG Nuclear LLC

Tim Kucey

None

N/A

5

Public Utility District No. 1
of Chelan County

Rebecca Zahler

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Becky Burden

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Loren Harbachuk

None

N/A

5

Sacramento Municipal
Utility District

Ryder Couch

Tim Kelley

Affirmative

N/A

5

Salt River Project

Thomas Johnson

Israel Perez

Affirmative

N/A

5

Santee Cooper

Carey Salisbury

Abstain

N/A

5

Seminole Electric
Cooperative, Inc.

Melanie Wong

None

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

Leslie Burke

Affirmative

N/A

5

Southern Indiana Gas and
Electric Co.

Larry Rogers

Abstain

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

Talen Generation, LLC

Donald Lock

Affirmative

N/A

Affirmative

N/A

5

Tallahassee Electric (City of
Karen Weaver
Tallahassee, FL)
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Bob Cardle

Ballot

Jennie Wike

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Tennessee Valley Authority

Darren Boehm

Negative

N/A

5

Tri-State G and T
Association, Inc.

Sergio Banuelos

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Kalidass

Abstain

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Abstain

N/A

6

AEP

Mathew Miller

Affirmative

N/A

6

Ameren - Ameren Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Marcus Bortman

Affirmative

N/A

6

Associated Electric
Cooperative, Inc.

Brian Ackermann

Affirmative

N/A

6

Austin Energy

Imane Mrini

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Lindsay Wickizer

None

N/A

6

Black Hills Corporation

Rachel Schuldt

Affirmative

N/A

6

Bonneville Power
Administration

Tanner Brier

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Negative

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Jason Chandler

Affirmative

N/A

6

Constellation

Kimberly Turco

Abstain

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Affirmative

N/A

6

Duke Energy

John Sturgeon

Affirmative

N/A

6

Edison International Southern California Edison
Company

Stephanie Kenny

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Evergy

Tiffany Lake

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

Hayden Maples

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

FirstEnergy - FirstEnergy
Corporation

Stacey Sheehan

Affirmative

N/A

6

Great River Energy

Brian Meloy

Negative

N/A

6

Imperial Irrigation District

Diana Torres

Affirmative

N/A

6

Lakeland Electric

Paul Shipps

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department of
Water and Power

Anton Vu

Abstain

N/A

6

Manitoba Hydro

Brandin Stoesz

None

N/A

6

Muscatine Power and
Water

Nicholas Burns

Abstain

N/A

6

New York Power Authority

Shelly Dineen

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

Negative

N/A

6

NiSource - Northern
Indiana Public Service Co.

Rebecca Blair

Negative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

NRG - NRG Energy, Inc.

Martin Sidor

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Ashley F Stringer

Affirmative

N/A

6

Omaha Public Power
District

Shonda McCain

Negative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Stefanie Burke

None

N/A

6

Powerex Corporation

Raj Hundal

Negative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

None

N/A

6
PSEG - PSEG Energy
Laura Wu
© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
Resources and Trade LLC

Denise Sanchez

Segment

Organization

Voter

6

Public Utility District No. 1
of Chelan County

Tamarra Hardie

6

Sacramento Municipal
Utility District

Charles Norton

6

Salt River Project

Timothy Singh

6

Santee Cooper

6

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Tim Kelley

Affirmative

N/A

Israel Perez

Affirmative

N/A

Marty Watson

Abstain

N/A

Seminole Electric
Cooperative, Inc.

Bret Galbraith

None

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation and Energy
Marketing

Matthew O'neal

Affirmative

N/A

6

Southern Indiana Gas and
Electric Co.

Kati Barr

Abstain

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

Affirmative

N/A

6

Western Area Power
Administration

Jennifer Neville

Affirmative

N/A

6

Xcel Energy, Inc.

Steve Szablya

None

N/A

8

Florida Reliability
Coordinating Council –
Member Services Division

Vince Ordax

Abstain

N/A

10

Midwest Reliability
Organization

Mark Flanary

Affirmative

N/A

10

New York State Reliability
Council

Wesley Yeomans

Affirmative

N/A

10

Northeast Power
Coordinating Council

Gerry Dunbar

Affirmative

N/A

10

ReliabilityFirst

Tremayne Brown

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01
10
Texas Reliability Entity, Inc.
Rachel Coyne

Affirmative

N/A

Jennie Wike

Greg Sorenson

Segment
10

Organization
Western Electricity
Coordinating Council

Voter
Steven Rueckert

Designated
Proxy

Abstain

Previous
Showing 1 to 314 of 314 entries

© 2024 - NERC Ver 4.2.1.0 Machine Name: ATLVPEROWEB01

NERC
Memo

Ballot

N/A

1

Next

Exhibit H
Standard Drafting Team Roster

RELIABILITY | RESILIENCE | SECURITY

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