NERC Petition, without Exhibits

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

)

Docket No. _________

)

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD
TPL-001-5

Lauren A. Perotti
Counsel
North American Electric Reliability Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099– facsimile
[email protected]
Counsel for the North American Electric
Reliability Corporation

December 7, 2018

TABLE OF CONTENTS
SUMMARY ............................................................................................................................ 3
NOTICES AND COMMUNICATIONS ................................................................................ 6
BACKGROUND ................................................................................................................. 6
A.

Regulatory Framework ..................................................................................................... 6

B.

NERC Reliability Standards Development Procedure ..................................................... 7

C.
2009 NERC Advisory, Order No. 754, and NERC Activities to Study Single Points of
Failure on Protection Systems .................................................................................................... 8
D.

Order No. 786 Approving TPL-001-4............................................................................ 11

E.

Project 2015-10 Single Points of Failure TPL-001 ........................................................ 12
JUSTIFICATION FOR APPROVAL................................................................................ 13

A.

Revisions to Address Studies of Single Points of Failure on Protection Systems ......... 14
1.

Revisions to Table 1, Footnote 13 .............................................................................. 15

2.

Revisions to the Table 1, Category P5 Planning Event .............................................. 21

3.

Revisions to Table 1, Extreme Events, Stability Column Events .............................. 22

4.
Corrective Action Requirements for the Revised Table 1 Category P5 and Stability
Extreme Events Items 2.e-2.h Studies .................................................................................. 24
B.

Revisions to Address Order No. 786 Directives ............................................................ 27
1.

Study of Known Planned Outages .............................................................................. 28

2.

Spare Equipment Strategy for Stability Analysis ....................................................... 32

C.

Other Revisions .............................................................................................................. 34

D.

Enforceability of the Proposed Reliability Standard ...................................................... 35
EFFECTIVE DATE .............................................................................................................. 35
CONCLUSION .................................................................................................................. 37

Exhibit A
Exhibit B
Exhibit C
Exhibit D
Exhibit E
Exhibit F
Exhibit G
Exhibit H

Proposed Reliability Standard TPL-001-5
Implementation Plan
Order No. 672 Criteria
Analysis of Violation Risk Factors and Violation Severity Levels
Mapping Document
Technical Rationale
Summary of Development and Complete Record of Development
Standard Drafting Team Roster

i

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

)

Docket No. ________

)

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD
TPL-001-5
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”) 1 and Section 39.5 2 of
the Federal Energy Regulatory Commission’s (“FERC” or “Commission”) regulations, the North
American Electric Reliability Corporation (“NERC”) 3 hereby submits for Commission approval
proposed Reliability Standard TPL-001-5 – Transmission System Planning Performance
Requirements. As discussed more fully herein, proposed Reliability Standard TPL-001-5
improves upon currently effective Reliability Standard TPL-001-4 by providing for more
comprehensive and robust planning studies, thereby improving reliability. Further, the proposed
standard addresses certain Commission directives from its Order No. 786 approving TPL-001-4. 4
NERC requests that the Commission approve the proposed Reliability Standard (Exhibit A) and
find that the proposed standard is just, reasonable, not unduly discriminatory or preferential, and
in the public interest. NERC also requests that the Commission approve: (i) the associated
Implementation Plan (Exhibit B); (ii) the associated Violation Risk Factors (“VRFs”) and

1

16 U.S.C. § 824o (2018).
18 C.F.R. § 39.5 (2018).
3
The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with
Section 215 of the FPA on July 20, 2006. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006), order on reh’g
& compliance, 117 FERC ¶ 61,126 (2006), aff’d sub nom. Alcoa, Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009).
4
Transmission Planning Reliability Standards, Order No. 786, 145 FERC ¶ 61,051 (2013).
2

1

Violation Severity Levels (“VSLs”), which remain unchanged from TPL-001-4 (Exhibit D); and
(iii) the retirement of currently effective Reliability Standard TPL-001-4.
As required by Section 39.5(a) 5 of the Commission’s regulations, this Petition presents
the technical basis and purpose of the proposed Reliability Standard, a demonstration that the
proposed Reliability Standard meets the criteria identified by the Commission in Order No. 672 6
(Exhibit C), and a summary of the standard development history (Exhibit G). The proposed
Reliability Standard was adopted by the NERC Board of Trustees on November 7, 2018.
This Petition is organized as follows: Section I of the Petition presents a summary of the
proposed Reliability Standard. Section II of the Petition provides the individuals to whom notices
and communications related to the filing should be provided. Section III provides background on
the regulatory structure governing the Reliability Standards approval process. This section also
provides information on the development of the proposed Reliability Standard through Project
2015-10 – Single Points of Failure TPL-001 and the Commission orders and NERC activities
that informed its development. Section IV of the Petition provides a detailed discussion of the
proposed Reliability Standard and explains how the proposed standard enhances reliability by
providing for more comprehensive consideration of Protection System 7 single points of failure,
known outages, and the unavailability of long lead-time equipment in planning studies. Section
V of the Petition provides a summary of the proposed implementation plan.

5

18 C.F.R. § 39.5(a).
The Commission specified in Order No. 672 certain general factors it would consider when assessing
whether a particular Reliability Standard is just and reasonable. See Rules Concerning Certification of the Electric
Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability
Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, at P 262, 321-37, order on reh’g, Order No. 672-A,
FERC Stats. & Regs. ¶ 31,212 (2006).
7
Unless otherwise indicated, capitalized terms shall have the meaning set forth in the Glossary of Terms
used in NERC Reliability Standards (“NERC Glossary”),
https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
6

2

SUMMARY
The TPL-001 Reliability Standard is one of two Transmission Planning Reliability
Standards that set forth Requirements for Planning Authorities and Transmission Planners to
develop studies of their portions of the Bulk Electric System (“BES”). The purpose of proposed
Reliability Standard TPL-001-5 is to “[e]stablish Transmission system planning performance
requirements within the planning horizon to develop a [BES] that will operate reliably over a
broad spectrum of System conditions and following a wide range of probable Contingencies.”
The proposed standard would require each Planning Authority and Transmission Planner to
perform an annual Planning Assessment 8 of its portion of the BES covering a number of System
conditions and Contingencies described in the standard.
The proposed standard employs a risk-based approach to the study of Contingencies and
the types of corrective action that are required if the entity’s System cannot meet the standard’s
performance requirements. This risk-based approach is carried forward from currently effective
Reliability Standard TPL-001-4. For the scenarios considered to be more commonplace
(“planning events”), the planning entity must develop a Corrective Action Plan if it determines,
through its studies, that its System would experience performance issues. For the scenarios
considered to be less commonplace but which could result in potentially severe impacts such as
Cascading (“extreme events”), the planning entity must conduct a comprehensive analysis to
understand both the potential impacts on its system and the types of actions that could reduce or
mitigate those impacts.
As discussed more fully in Section V, proposed Reliability Standard TPL-001-5 improves
upon the currently effective standard by enhancing Requirements for the study of Protection

8

“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.”

3

System single points of failure. In this context, a Protection System “single point of failure”
refers to a non-redundant component of a Protection System that, if it failed, would affect
Normal Clearing 9 of faults. NERC identified this issue as a reliability risk to be addressed based
on its analysis of potential single points of failure on the BES using data obtained pursuant to a
request for data under Section 1600 of the NERC Rules of Procedure. The proposed standard
contains revisions to both the Table 1 planning event (Category P5) and extreme events (Stability
2.a-h) and the associated footnote 13 to provide for more comprehensive study of the potential
impacts of Protection System single points of failure. Planning entities would be required to take
action, consistent with currently effective TPL-001 Requirements, to address System
performance issues identified as a result of these studies.
Additionally, the proposed standard addresses two Commission directives from Order
No. 786. 10 First, the proposed standard provides for a more complete consideration of factors for
selecting which known outages will be included in Near-Term Transmission Planning Horizon
studies. The modifications reflected in proposed TPL-001-5 address the Commission’s concern
that the exclusion of known outages of less than six months in TPL-001-4 could result in outages
of significant facilities not being studied. 11 Second, the proposed standard modifies
Requirements for Stability analysis to require an entity to assess the impact of the possible
unavailability of long lead time equipment, consistent with the entity’s spare equipment
strategy. 12

9
“Normal Clearing” is defined in the NERC Glossary as “a protection system operates as designed and the
fault is cleared in the time normally expected with proper functioning of the installed protection systems.”
10
See Order No. 786 at PP 40, 89.
11
See id. at PP 41-45.
12
See id. at P 89 (directing NERC to consider such a revision upon the next review cycle of TPL-001-4).

4

Collectively, these revisions would help improve the quality and rigor of Planning
Assessments, thereby contributing to a more reliable Bulk-Power System (“BPS”). The proposed
standard also contains an update and a limited number of editorial revisions which improve the
readability and organization of the standard.
As discussed more fully in Section V, NERC’s proposed phased implementation plan
strikes an appropriate balance between implementing the standard in a reasonably expeditious
manner and allowing entities sufficient time to come into compliance. The proposed
implementation plan recognizes the significant coordination and work that would need to be
done to identify, study, and address potential Protection System single points of failure issues.
Under the proposed plan, the proposed standard would become effective 36 months after
regulatory approval, with additional time afforded to entities to come into compliance with
provisions related to Protection System single point of failure analysis and related Corrective
Action Plans.
For these reasons, and as discussed more fully herein, NERC respectfully requests that
the Commission approve the proposed Reliability Standard and the related elements effective as
proposed by NERC.

5

NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the following: 13
Shamai Elstein*
Senior Counsel
Lauren A. Perotti*
Counsel
North American Electric Reliability Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099– facsimile
[email protected]
[email protected]

Howard Gugel*
Senior Director of Engineering and Standards
North American Electric Reliability Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile
[email protected]

BACKGROUND
A.

Regulatory Framework

By enacting the Energy Policy Act of 2005, 14 Congress entrusted the Commission with
the duties of approving and enforcing rules to ensure the reliability of the BPS, and with the
duties of certifying an ERO that would be charged with developing and enforcing mandatory
Reliability Standards, subject to Commission approval. Section 215(b)(1) 15 of the FPA states that
all users, owners, and operators of the BPS in the United States will be subject to Commissionapproved Reliability Standards. Section 215(d)(5) 16 of the FPA authorizes the Commission to
order the ERO to submit a new or modified Reliability Standard. Section 39.5(a) 17 of the
Commission’s regulations requires the ERO to file with the Commission for its approval each
new Reliability Standard that the ERO proposes should become mandatory and enforceable in
13

Persons to be included on the Commission’s service list are identified by an asterisk. NERC respectfully
requests a waiver of Rule 203 of the Commission’s regulations, 18 C.F.R. § 385.203, to allow the inclusion of more
than two persons on the service list in this proceeding.
14
16 U.S.C. § 824o.
15
Id. § 824o(b)(1).
16
Id. § 824o(d)(5).
17
18 C.F.R. § 39.5(a).

6

the United States, and each modification to a Reliability Standard that the ERO proposes should
be made effective.
The Commission is vested with the regulatory responsibility to approve Reliability
Standards that protect the reliability of the BPS and to ensure that Reliability Standards are just,
reasonable, not unduly discriminatory or preferential, and in the public interest. Pursuant to
Section 215(d)(2) of the FPA 18 and Section 39.5(c) 19 of the Commission’s regulations, the
Commission will give due weight to the technical expertise of the ERO with respect to the
content of a Reliability Standard.
B.

NERC Reliability Standards Development Procedure

The proposed Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process. 20 NERC
develops Reliability Standards in accordance with Section 300 (Reliability Standards
Development) of its Rules of Procedure and the NERC Standard Processes Manual. 21
In its order certifying NERC as the Commission’s ERO, the Commission found that
NERC’s rules provide for reasonable notice and opportunity for public comment, due process,
openness, and a balance of interests in developing Reliability Standards, 22 and thus satisfy
certain of the criteria for approving Reliability Standards. 23 The development process is open to
any person or entity with a legitimate interest in the reliability of the BPS. NERC considers the

18

16 U.S.C. § 824o(d)(2).
18 C.F.R. § 39.5(c)(1).
20
Order No. 672, Rules Concerning Certification of the Electric Reliability Organization; and Procedures for
the Establishment, Approval, and Enforcement of Electric Reliability Standards, FERC Stats. & Regs. ¶ 31,204,
order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
21
The NERC Rules of Procedure are available at http://www.nerc.com/AboutNERC/Pages/Rules-ofProcedure.aspx. The NERC Standard Processes Manual is available at
http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
22
N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 at P 250 (2006).
23
Order No. 672 at PP 268, 270.
19

7

comments of all stakeholders. Stakeholders must approve, and the NERC Board of Trustees must
adopt, a Reliability Standard before NERC submits the Reliability Standard to the Commission
for approval.
C.

2009 NERC Advisory, Order No. 754, and NERC Activities to Study Single
Points of Failure on Protection Systems

On March 30, 2009, NERC issued an advisory report notifying the industry that failure of
a single component of a Protection System caused three significant system disturbances in the
previous five years. 24 Transmission Owners, Generation Owners, and Distribution Providers
owning Protection Systems installed on the BES were advised to address single points of failure
on their Protection Systems, when identified in routine system evaluations, to prevent N-1
transmission system contingencies from evolving into more severe or even extreme events.
These entities were also advised to begin preparing an estimate of the resource commitment
required to review, re-engineer, and develop a workable outage and construction schedule to
address single points of failure.
On September 15, 2011, the Commission issued Order No. 754 approving an
interpretation of TPL-002-0 Requirement R1.3.10. 25 In this Order, the Commission stated that it
believed there is “an issue concerning the study of the non‐operation of non‐redundant primary
protection systems; e.g., the study of a single point of failure on protection systems.” 26 To
address this concern, the Commission directed “Commission staff to meet with NERC and its
appropriate subject matter experts to explore the reliability concern, including where it can best

24

NERC, Industry Advisory, Protection System Single Point of Failure (Mar. 20, 2009),
https://www.nerc.com/fileUploads/File/Events%20Analysis/A-2009-03-30-01.pdf.
25
Interpretation of Transmission Planning Reliability Standard, Order No. 754, 136 FERC ¶ 61,186 (2011).
Reliability Standard TPL-002-0 was a predecessor to the currently-effective TPL-001-4 standard.
26
Id. at P 19.

8

be addressed, and identify any additional actions necessary to address the matter.” 27 FERC also
directed NERC to “to make an informational filing…explaining whether there is a further system
protection issue that needs to be addressed and, if so, what forum and process should be used to
address that issue and what priority it should be accorded relative to other reliability initiatives
planned by NERC.” 28
In March 2012, NERC submitted an informational filing to the Commission summarizing
the results of its early work to study the issue. 29 As described more fully in that filing, NERC
staff, FERC technical staff, and industry stakeholders attended a technical conference on October
24–25, 2011, the purpose of which was to focus on the Commission’s concern regarding
assessment of Protection System failures. One outcome of the 2011 technical conference was
that NERC would conduct a data collection effort to aid in assessing whether single points of
failure in protection systems pose a reliability concern. To that end, the NERC Board of Trustees
approved a request for data under Section 1600 of the NERC Rules of Procedure (the “Order No.
754 Data Request”) on August 16, 2012. 30
Over the next two years, NERC collected data from Transmission Planners. Using the
collected data, two subcommittees of the NERC Planning Committee, the System Protection and
Control Subcommittee (“SPCS”) and the System Analysis and Modeling Subcommittee
(“SAMS”), conducted an assessment of Protection System single points of failure. The findings

27

Id. at P 20.
Id.
29
Informational Filing of the North American Electric Reliability Corporation in Response to Order No. 754,
Docket No. RM10-6-000 (Mar. 15, 2012).
28

30

Request for Data or Information: Order No. 754 Single Point of Failure on Protection Systems (Aug. 16,
2012), http://www.nerc.com/pa/Stand/Pages/order_754.aspx. The process governing Requests for Data or
Information is contained in Section 1600 of the NERC Rules of Procedure,
http://www.nerc.com/AboutNERC/Pages/Rules-of-Procedure.aspx.

9

were presented in a September 2015 report titled Order No. 754: Assessment of Protection
System Single Points of Failure Based on the Section 1600 Data Request. 31 In the report, the
SPCS and SAMS found that single points of failure on Protection Systems did pose a reliability
risk that warranted further action. The report concluded:
Analysis of the data demonstrates the existence of a reliability risk
associated with single points of failure in protection systems that
warrants further action. The analysis shows that the risk from single
point of failure is not an endemic problem and instances of single
point of failure exposure are lower on higher voltage systems.
However, the risk is sufficient to warrant further action. Risk‐based
assessment should be used to identify protection systems of concern
(i.e., locations on the BES where there is a susceptibility to
cascading if a protection system single point of failure exists). Not
all failures adversely affect reliable operation of the bulk power
system. The reliability risk varies based on which component of a
protection system fails. 32
The SPCS and the SAMS recommended, after considering a variety of alternatives to
address this reliability concern, that NERC modify Reliability Standard TPL‐001‐4 through the
NERC standards development process. The SPCS and the SAMS concluded that this approach
best aligns with FERC Order No. 754 directives and maximizes reliability of Protection System
performance. The report recommended that three-phase faults involving Protection System
failures be assessed as an extreme event in the TPL-001 standard, as follows:
Additional emphasis in planning studies should be placed on
assessment of three‐phase faults involving protection system single
points of failure. This concern (the study of protection system single
points of failure) is appropriately addressed as an extreme event in
31

NERC SPCS/SAMS, Order No. 754: Assessment of Protection System Single Points of Failure Based on
the Section 1600 Data Request (Sep. 2015) (“SPCS/SAMS Report”),
https://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/FE
RC%20Order%20754%20Final%20Report%20-%20SPCS-SAMS.pdf.
NERC submitted this report to the Commission on an informational basis on October 30, 2015 in Docket
No. RM10-6-000. See Informational Filing of NERC, Assessment of Protection System Single Points of Failure,
Docket No. RM10-6-000 (Oct. 30, 2015).
32
SPCS/SAMS Report at 11.

10

TPL‐001‐4 Part 4.5. From TPL‐001‐4, Part 4.5: If the analysis
concludes there is cascading caused by the occurrence of extreme
events, an evaluation of possible actions designed to reduce the
likelihood or mitigate the consequences and adverse impacts of the
event(s) shall be conducted. 33
Following the issuance of this report, NERC initiated a standards development project to
consider the specific recommendations from this report. Later, NERC expanded the scope of the
project to address two Commission directives from Order No. 786 approving TPL-001-4, as
discussed further below.
D.

Order No. 786 Approving TPL-001-4

In Order No. 786, the Commission approved the currently effective version of the
transmission system planning standard, TPL-001-4. In that Order, the Commission also issued
several directives to NERC, including two relating to future standard modifications that are
addressed in proposed Reliability Standard TPL-001-5.
First, the Commission expressed concern that the six month outage duration threshold in
TPL-001-4 Requirement R1 could exclude planned maintenance outages of significant facilities
from future planning assessments. The Commission found that “planned maintenance outages of
less than six months in duration may result in relevant impacts during one or both of the seasonal
off-peak periods,” and that “[p]rudent transmission planning should consider maintenance
outages at those load levels when planned outages are performed to allow for a single element to
be taken out of service for maintenance without compromising the ability of the system to meet
demand without loss of load.” 34 The Commission further stated, “[a] properly planned
transmission system should ensure the known, planned removal of facilities (i.e., generation,

33
34

Id. at 11; see also id. at 9 (discussion of alternatives to address reliability risks).
Order No. 786 at P 41.

11

transmission or protection system facilities) for maintenance purposes without the loss of nonconsequential load or detrimental impacts to system reliability such as cascading, voltage
instability or uncontrolled islanding.” 35 The Commission directed NERC to modify the TPL-001
standard to address this concern.
Second, while stating that NERC had met the Commission’s Order No. 693 directive to
include a spare equipment strategy for steady state analysis in TPL-001-4, the Commission found
that a spare equipment strategy for stability analysis was not addressed in the standard. 36 The
Commission stated that it “believes that a similar spare equipment strategy for stability analysis
should exist that requires studies to be performed for P0, P1 and P2 categories with the
conditions that the system is expected to experience during the possible unavailability of the long
lead time equipment.” 37 Rather than direct a change at that time, however, the Commission
directed NERC to consider the issue during the next review cycle of TPL-001-4. 38
E.

Project 2015-10 Single Points of Failure TPL-001

In October 2015, NERC initiated Project 2015-10 Single Points of Failure TPL-001 to
address the Protection System single points of failure recommendations from the SPCS/SAMS
report. Subsequently, the scope of the project was expanded to add consideration of the
Commission’s Order No. 786 directives and an update to a MOD standard reference in the TPL001 standard. In developing the proposed standard, the standard drafting team considered the

35

Id.
Order No. 786 at P 88. In Order No. 693, the Commission directed NERC to modify TPL-001-0 “to require
assessments of outages of critical long lead time equipment, consistent with the entity’s spare equipment strategy.”
See Mandatory Reliability Standards for the Bulk-Power System, Order No. 693 at P 1768, FERC Stats. & Regs. ¶
31,242 (2007) (Order No. 693), order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007). This led to the
development of TPL-001-4 Requirement R2, Part 2.1.5 addressing steady-state conditions to determine system
response when critical equipment is unavailable for a prolonged period of time.
37
Order No. 786 at P 89.
38
Id.
36

12

discussion and recommendations of the SPCS/SAMS report on Protection System single points
of failure. The standard drafting team also considered additional recommendations developed by
the SAMS to address the two Order No. 786 directives, 39 feedback received throughout the
standard development process, and its own experience and expertise in the subject matter area. 40
The proposed standard and implementation plan were posted once for informal comment
and three times for formal comment and ballot. The fifth draft of proposed Reliability Standard
TPL-001-5 and the associated implementation plan were approved by the ballot body on October
22, 2018. The proposed standard received a 66.69 percent approval rating, with 86.39 percent
quorum. The proposed implementation plan received a 72.44 percent approval rating, with 86.73
percent quorum. The NERC Board of Trustees adopted the proposed standard on November 7,
2018. A summary of the development history and the complete record of development is
attached to this Petition as Exhibit G.
JUSTIFICATION FOR APPROVAL
As discussed in Exhibit C and below, proposed Reliability Standard TPL-001-5 satisfies
the Commission’s criteria in Order No. 672 and is just, reasonable, not unduly discriminatory or
preferential, and in the public interest. The purpose of the proposed standard is to “[e]stablish
Transmission system planning performance requirements within the planning horizon to develop
a Bulk Electric System (BES) that will operate reliability over a broad spectrum of System
conditions and following a wide range of probable Contingencies.” As with the purpose

39

NERC SAMS, FERC Order 786 Directives (2016),
https://www.nerc.com/comm/PC/System%20Analysis%20and%20Modeling%20Subcommittee%20SAMS%20201/
FERC%20Order%20786%20Directives%20-%20SAMS%20White%20Paper%20-%202016-07-22.pdf.
40
The standard drafting team roster for Project 2015-10 Single Points of Failure TPL-001 is attached to this
Petition as Exhibit H.

13

statement, the applicability of the proposed standard (Planning Coordinators and Transmission
Planners) remains unchanged from the currently effective standard.
Proposed Reliability Standard TPL-001-5 improves upon the currently effective version
of the standard by revising the existing Table 1 planning and extreme events to require a more
complete, risk-based analysis of how the failure of a non-redundant component of a Protection
System would affect a planning entity’s System. The proposed standard also improves upon the
currently effective standard and addresses the Commission’s standard modification directives
from Order No. 786 by: (i) requiring a more comprehensive analysis of known outages in
planning studies; and (ii) requiring entities to consider, in Stability analysis, the impacts of the
possible unavailability of long lead time equipment, consistent with the entity’s spare equipment
strategy. Lastly, the proposed standard contains an update to a MOD standard reference and
editorial revisions to improve organization.
The proposed standard revisions and the justification for each is provided below. The
proposed revisions are shown in the TPL-001-5 redline attached to this Petition as Exhibit A.
A.

Revisions to Address Studies of Single Points of Failure on Protection
Systems

Proposed Reliability Standard TPL-001-5 contains a series of revisions to help ensure
that planning entities are: (1) performing a more complete analysis of potential Protection
System single point of failure issues on their Systems; and (2) taking appropriate action to
address these concerns. The SPCS/SAMS report concluded that “the data demonstrates the
existence of a reliability risk associated with single points of failure in protection systems that
warrants further action” and that “risk-based assessment should be used to identify protection
systems of concern (i.e., locations on the BES where there is a susceptibility to cascading if a

14

protection system single point of failure exists).” 41 To address this concern, proposed Reliability
Standard TPL-001-5 revises:
•

the Table 1, Category P5 planning event, which would require the planning entity to
study the impact on its System of Delayed Fault Clearing 42 due to the failure of a nonredundant component of a Protection System protecting the Faulted element to operate
as designed;

•

the Table 1, Stability Extreme Events 2.a-2.h, which would require the planning entity
to study the impact on its System of a three-phase fault with failure of a non-redundant
component of a Protection System resulting in Delayed Fault Clearing; and

•

Table 1, footnote 13, which specifies the Protection System equipment to be considered
as part of studying the Category P5 planning event and Stability Extreme Events 2.e2.h.

Collectively, the proposed revisions help ensure that planning entities are performing a
risk-based assessment of the potential impacts of Protection System single points of failure that
could pose a risk to reliability. Each of these revisions in the proposed standard is discussed
below, beginning with the revisions to Table 1, footnote 13 which specify the non-redundant
Protection System components to be considered as part of planning studies.
1. Revisions to Table 1, Footnote 13
Proposed Reliability Standard TPL-001-5 employs a risk-based approach to the study of
Protection System single points of failure. Accordingly, proposed Table 1, footnote 13 is
intended to focus the planning entity’s consideration on those non-redundant components of a

41

SPCS/SAMS Report at 11.
“Delayed Fault Clearing” is defined in the NERC Glossary as “Fault clearing consistent with correct
operation of a breaker failure protection system and its associated breakers, or of a backup protection system with an
intentional time delay.”
42

15

Protection System that may, when they fail, lead to Delayed Fault Clearing when simulating the
Category P5 planning event and Stability extreme events 2.e-h.
In proposed Reliability Standard TPL-001-5, the limited set of relay functions or types in
Table 1, Footnote 13 is replaced with an expanded list of components to capture the Protection
System single point of failure concern. Guided by the SPCS/SAMS report recommendations, the
TPL-001-5 standard drafting team selected a list of components to account for: (1) those failed
non-redundant components of a Protection System that may impact one or more Protection
Systems; (2) the duration that faults remain energized until Delayed Fault Clearing; and (3) the
additional system equipment removed from service following fault clearing depending on the
specific failed non-redundant component of a Protection System. 43
Footnote 13 is revised to list four specific types of non-redundant Protection System
components, as follows:
13.

Applies to the following relay functions or types: pilot (#85),
distance (#21), differential (#87), current (#50, 51, and 67), voltage
(#27 & 59), directional (#32, & 67), and tripping (#86, & 94).

13.

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

43

See Technical Rationale at 4-5. Additional information regarding the selection of each particular
component is available in the Technical Rationale on pages 5-10.

16

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).

The revised Footnote 13 does not include all Protection System components in the list of
potential non-redundant components to consider. The SPCS/SAMS report described failure of
voltage or current sensing devices as having a lower level of risk of failure to trip. 44 The
reliability risk associated with the failure of these components is lower than the risk posed by the
failure of a Protection System component that is needed to clear a fault. Therefore, voltage or
current sensing devices are not included in the revised footnote 13. Similarly, control circuitry
whose failure does not prevent Normal Clearing of a fault, such as reclosing circuitry and
reclosing relays, is not considered under the revised footnote 13. 45
An explanation for each of the types of devices to be included in Protection System
single point of failure studies under revised footnote 13a.-d is provided below.
a)

Footnote 13.a – Protective Relays

Footnote 13.a includes among the components to consider “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.” Other Requirements
address simulation of Protection System action. 46 Footnote 13.a therefore limits the potential

44
45
46

See Technical Rationale at 5; see also SPCS/SAMS Report at 7.
See Technical Rationale at 5.
See TPL-001-5 Requirement R3 Part 3.3.1 and Requirement R4 Part 4.3.1.

17

single points of failure to study to those single protective relays which respond to electrical
quantities and are used for primary protection resulting in Normal Clearing. A single point of
failure in such a relay may result in the primary Protection System failing to operate properly,
leading to Delayed Fault Clearing performed by backup protective relays and/or overlapping
zonal protection. 47 For footnote 13.a, an “alternative that provides comparable Normal Clearing
times” refers to a relay that results in fault clearing within the expected Normal Clearing time
period and isolates the fault by tripping similar System Elements than if the single protective
relay that is simulated to fail were to function properly. By noting that the alternative may or
may not respond to electrical quantities, Footnote 13.a accounts for those Protection System
designs in which non-redundant single protective relays which respond to electrical quantities
may be redundant to protective relays that do not respond to electrical quantities. 48
b)

Footnote 13.b – Communications Systems

Footnote 13.b includes among the Protection System components to consider a “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).” Given the
increasing importance of communication-aided Protection Systems, the proper operation of the
communication system must be considered when considering potential Protection System
components to study for single points of failure concerns. A communication-aided Protection
System that may experience a single point of failure, causing it to operate improperly or not at
all, must be considered among non-redundant components.

47
Footnote 13.a does not include backup protective relays given that a single point of failure in a single
protective relay used for backup protection will not affect primary protection resulting in Normal Clearing.
48
For an example of such a design, see the Technical Rationale at 5-7.

18

Footnote 13 provides that certain non-redundant components that are both monitored and
reported at a Control Center would not need to be considered as part of planning studies. This
includes the communications systems identified in footnote 13.b. The standard drafting team
considered that the monitoring and reporting of a non-redundant component to a centralized
location (i.e., the Control Center) would facilitate prompt identification and correction of
abnormal conditions to minimize the exposure to and consequence of the failed component.
Therefore, it concluded that such monitored and reported components exhibited a lower risk, on
par with being redundant, than a non-redundant component that reported to a remote location or
one whose failure might go undetected for some time. 49
c)

Footnote 13.c – Station DC Supply

Footnote 13.c includes among the Protection System components to consider “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).” Failure of a single station Protection System DC supply is a significant
point of failure as it will prevent the operation of all local protection, including back-up protection.
Similar to footnote 13.b, monitoring and reporting the status of the DC supply to a centralized
location can be considered a sufficient alternative to physical redundancy if the result is prompt
notification and remediation which minimizes the exposure to and consequence of DC supply
failure.
d)

Footnote 13.d – Control Circuitry

Lastly, footnote 13.d would require consideration of “a single control circuitry (including
auxiliary relays and lockout relays) associated with protective functions, from the dc supply

49

Technical Rationale at 5.

19

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).” Failure of a Protection System single control circuitry is a significant point
of failure as it will prevent proper tripping and, depending upon its design and mode of failure,
may also prevent the initiation of breaker failure protection. 50 Further, most, if not all,
constituent parts of the control circuitry are generally unmonitored, may fail, and may remain
undetected until periodic testing is conducted. This is particularly significant for non-redundant
auxiliary relays or lockout relays within the control circuitry because they may be used for
multiple functions, such as multiplexing trip signals for differential or breaker failure initiation.
Single control circuitry should be considered a non-redundant component of a Protection System
given that Delayed Fault Clearing, including significantly delayed remote end or backup
clearing, is expected when the non-redundant auxiliary or lockout relay device within the single
control circuitry fails.
The single control circuitry is demarcated from the DC supply through and including the
trip coil(s) for the purpose of including all devices in the control circuitry which, if failed, may
prevent proper Protection System action leading to Delayed Fault Clearing. Trip coils are
commonly employed in pairs for the purpose of incorporating redundancy to actuate the tripping
of a circuit breaker or other interrupting device. When a single trip coil is employed, monitoring
and reporting the status of the single trip coil to the Control Center can be considered as a
sufficient alternative to its physical redundancy given that prompt notification and remediation is
expected, which minimizes the risk the trip coil failure. However, all constituent parts of the

50

Breaker failure is addressed by the Table 1, Category P4 planning event.

20

single control circuit (including wires) should be included when considering whether the single
control circuit may be a non-redundant component of a Protection System.
2. Revisions to the Table 1, Category P5 Planning Event
The Category P5 event in Table 1 of proposed Reliability Standard TPL-001-5 would
require the planning entity to simulate a Contingency where a single line-to-ground fault occurs
and Delayed Fault Clearing results due to the failure of a non-redundant component of a
Protection System protecting the Faulted element to operate as designed. Stated differently, the
Protection System does not operate as designed to clear the single line-to-ground fault in the time
normally expected with proper functioning of the Protection System due to a single point of
failure. When a Protection System does not operate as designed or fails to isolate faulted
equipment within the time normally expected with its proper functioning, backup protection
capabilities must act to clear the fault. Such backup systems are designed with intentional time
delays before fault clearing. Additionally, the operation of these backup systems could result in
significant differences in final System configuration. For example, more System Elements may
be removed from service when the backup Protection System operates than may be expected
during primary Protection System operation.
Revisions are proposed to the Category P5 event to be consistent with the revisions to
footnote 13, replacing the word “relay” with the more inclusive phrase “component of a
Protection System”, as follows:

21

Consistent with currently effective Reliability Standard TPL-001-4, the entity would be
required to develop a Corrective Action Plan in the event it determines that its System would be
unable to meet the performance requirements of Table 1 for the Category P5 event. Corrective
action requirements for the revised Protection System single point of failure studies are discussed
in Section IV.A.4, below.
3. Revisions to Table 1, Extreme Events, Stability Column Events
Consistent with the recommendations of the SPCS/SAMS report, proposed Reliability
Standard TPL-001-5 revises the Table 1 Extreme Events to place additional emphasis on
assessment of three-phase faults involving single points of failure on a Protection System. In
proposed Reliability Standard TPL-001-5, the extreme events in the Stability column of Table 1
is revised so that four distinct items, 2.e-2.h, would address study of Protection System single
points of failure in combination with three-phase faults, as follows:
Table 1, Steady State & Stability Performance Extreme Events
Stability
***
2. Local or wide area events affecting the Transmission System such
as:
a. 3Ø fault on generator with stuck breaker10 or a relay failure13
resulting in Delayed Fault Clearing.

22

b. 3Ø fault on Transmission circuit with stuck breaker10 or a
relay failure13 resulting in Delayed Fault Clearing.
c. 3Ø fault on transformer with stuck breaker10 or a relay
failure13 resulting in Delayed Fault Clearing.
d. 3Ø fault on bus section with stuck breaker10 or a relay
failure13 resulting in Delayed Fault Clearing.
e. 3Ø fault on generator with failure of a non-redundant
component of a Protection System13 resulting in Delayed
Fault Clearing.
f. 3Ø fault on Transmission circuit with failure of a nonredundant component of a Protection System13 resulting in
Delayed Fault Clearing.
g. 3Ø fault on transformer with failure of a non-redundant
component of a Protection System13 resulting in Delayed
Fault Clearing.
h. 3Ø fault on bus section with failure of a non-redundant
component of a Protection System13 resulting in Delayed
Fault Clearing.
e.i. 3Ø internal breaker fault.
f.j. Other events based upon operating experience, such as
consideration of initiating events that experience suggests
may result in wide area disturbances
As demonstrated above, Table 1, Extreme Events, Stability column, items 2.a. through
2.d are revised to strike the term “relay failure.” Items 2.e through 2.h are added to address
specifically the study of a three-phase fault on a generator, Transmission circuit, transformer, or
bus section in combination with a failure of a non-redundant component of a Protection System
resulting in Delayed Fault Clearing. Footnote 13, discussed above, identifies the specific nonredundant components of a Protection System that should be considered as part of these extreme
event studies.
As discussed in the following section, proposed Reliability Standard TPL-001-5 carries
forward requirements from TPL-001-4 relating to the action the planning entity must take in the
event its studies indicate System performance issues for this event.

23

4. Corrective Action Requirements for the Revised Table 1 Category P5 and
Stability Extreme Events Items 2.e-2.h Studies
The proposed TPL-001-5 Reliability Standard, like the currently effective TPL-001-4
standard, takes a risk-based approach to System planning studies. Generally, the standard
contains more stringent corrective action requirements for the more commonplace scenarios, and
less stringent corrective action requirements for the rarest, but potentially most severe, scenarios.
This general framework is based on widely-accepted principles of cost-effective, risk-based
planning. As the Commission stated in a prior proceeding, “The Commission agrees that [the
extreme event Transmission Planning] Reliability Standard should not require improvements for
low probability events that cannot be justified.” 51 The planning entity should, however, be
required to fully understand the potential impacts such events could have on its System and the
steps that could be taken to address those impacts. 52 The planning entity would then use this
information to make an informed decision on the best way to plan its System for these rare
scenarios. This decision should take into account all relevant considerations. By way of example,
those considerations could include the entity’s planning priorities, the probability of the event,
and the expected impacts of the event. These considerations could also include the interests of its
customers and the entity’s ability to obtain cost recovery.
Proposed Reliability Standard TPL-001-5 carries forward this risk-based approach to the
study of Protection System single points of failure. As discussed in the previous sections, TPL001-5 replaces “relays” as the equipment to be studied in the Table 1, Category P5 planning

51

See Notice of Proposed Rulemaking, Mandatory Reliability Standards for the Bulk-Power System, 117
FERC ¶ 61,084 (Oct. 20, 2006) at P 1112 (proposing to approve Reliability Standard TPL-004-0 – System
Performance Following Extreme BES Events, which is a predecessor to the currently effective TPL-001-4 standard).
52

See id. and Order No. 693 at P 1836 (approving TPL-004-0 and directing NERC to modify the standard to
require, among other things, “the identification of options for reducing the probability or impacts of extreme events
that cause cascading.”)

24

event and Stability extreme events items 2.e-2.h with a broader list of potentially problematic
non-redundant Protection System components. The approach to mitigation for these events
remains unchanged from currently effective TPL-001-4.
The single line-to-ground fault scenario described in the revised Category P5 planning
event is considered to be the more commonplace scenario involving Protection System single
points of failure; therefore, if the planning entity determines that its System is unable to meet the
standard’s performance requirements, it must develop a Corrective Action Plan to address the
deficiencies. Requirement R2.7 in proposed Reliability Standard TPL-001-5 addresses
Corrective Action Plan requirements and remains substantively unchanged from the currently
effective standard. Such Corrective Action Plans for the Category P5 planning event may include
adding redundant components; however, this is only one of many alternatives for corrective
actions that planning entities may consider to achieve required System performance.
By contrast, the three phase fault scenario described in the revised Table 1, Extreme
Events, Stability column items 2.e-h is considered to be the much rarer occurrence, as discussed
further below. Like the other extreme events in the proposed standard, this scenario, while rare,
could result in more significant impacts to an entity’s System. During the development of the
proposed standard, the standard drafting team considered several alternative approaches to the
study of Protection System single points of failure with three-phase faults, particularly the type
of mitigation action that should be required by the standard. Taking into account all relevant
considerations, including industry feedback and the recommendations of the SPCS/SAMS report,
the TPL-001-5 drafting team determined that the most appropriate and cost effective approach
would be to carry forward the approach of currently effective TPL-001-4. Under this approach, if

25

an entity determines that its System will experience Cascading 53 as a result of a three-phase fault
scenario, “an evaluation of possible actions designed to reduce the likelihood or mitigate the
consequence(s) of the event shall be conducted.” In proposed Reliability Standard TPL-001-5,
this Requirement is carried forward in Requirement R4 Part 4.2. 54 The ERO would continue to
audit compliance with this analysis provision similarly to how it is audited under the currently
effective standard, taking into account the expanded list of Protection System components
considered in the study.
The corrective action requirements for the revised single line-to-ground fault and three
phase fault scenarios fit within the risk-based framework of the TPL-001 standard. Data
collected by NERC since 2011 provides further support that this framework remains appropriate
for Protection System single points of failure studies. Like all of the “extreme event” scenarios in
this framework, the impacts of a Protection System single point of failure in combination with a
three phase fault could be severe in some cases, but are very unlikely. A historical analysis of
NERC’s data on Protection System misoperations indicates that the expected likelihood of such
an event occurring and resulting in the most severe impacts would be small. NERC recently
completed a review of over 12,000 Protection System misoperations in its Misoperation
Information Data Analysis System (“MIDAS”) database reported since 2011. 55 Of the over

53

Cascading is defined in the NERC Glossary as: “The uncontrolled successive loss of System Elements
triggered by an incident at any location. Cascading results in widespread electric service interruption that cannot be
restrained from sequentially spreading beyond an area predetermined by studies.”
54
This provision is unchanged from currently-effective TPL-001-4, except that it is moved from Requirement
R4 Part 4.5 to Part 4.2 in proposed TPL-001-5 for editorial reasons. Similarly, the provision applicable to steady
state extreme events analysis is moved from Requirement R3 Part 3.5 to Part 3.2.
55
The ERO began to collect misoperations data in a common format beginning in 2011. Applicable entities
are currently required to report information on Protection System misoperations to NERC pursuant to a request for
data or information under Section 1600 of the NERC Rules of Procedure approved by the NERC Board of Trustees
on August 14, 2014. Previously, the PRC-004 standard contained requirements for misoperation reporting.

26

12,000 Protection System misoperations in MIDAS, 28 involved three-phase faults. Of that
number, only 10 involved breakers that failed to operate (the remaining 18 involved breakers that
were slow to operate). Failure to operate potentially indicates instances of a Protection System
single point of failure. While the potential for severe impacts from such events remains, none of
the 10 failure to trip scenarios reported since 2011 resulted in events that reached the threshold
for reporting to NERC under Reliability Standard EOP-004. 56
For these reasons, it remains appropriate to carry forward the risk-based mitigation
approach in currently effective Reliability Standard TPL-001-4 to the revised Protection System
single points of failure planning studies in proposed Reliability Standard TPL-001-5.
B.

Revisions to Address Order No. 786 Directives

In addition to addressing reliability issues involving single points of failure on Protection
Systems, proposed Reliability Standard TPL-001-5 revises the TPL-001 standard to address two
Commission directives from Order No. 786. Under the first directive, the Commission directed
NERC to modify TPL-001-4 to address the concern that the six month threshold could exclude
planned maintenance outages of significant facilities from future planning assessments. 57 Under
the second directive, the Commission directed NERC to consider whether TPL-001-4 should
contain a spare equipment strategy for Stability analysis, similar to that for steady state
analysis. 58 For steady state analysis, TPL-001-4 Requirement R2 Part 2.1.5 requires studies to be
performed for P0, P1, and P2 categories with the conditions that the system is expected to

56

The EOP-004 Reliability Standard specifies Requirements for entities to report disturbances and events that
have the potential to impact the reliability of the BPS.
57
Order No 786 at P 40.
58
Id. at P 89.

27

experience during the possible unavailability of the long lead-time equipment. A discussion of
the revisions in proposed TPL-001-5 to address these directives is provided below.
1. Study of Known Planned Outages
In proposed Reliability Standard TPL-001-5, NERC made several revisions to address the
Commission’s concern in Order No. 786 that the six-month threshold in TPL-001-4 Requirement
R1 Part 1.1.2 could exclude planned maintenance outages of significant facilities from future
planning assessments. 59 The proposed revisions are intended to complement Reliability Standard
IRO-017-1, which requires: (1) each Reliability Coordinator to maintain an outage coordination
process within its Reliability Coordinator Area; and (2) each Planning Coordinator and
Transmission Planner to provide its Planning Assessment to impacted Reliability Coordinators
and to jointly develop solutions with its Reliability Coordinator(s) for identified issues or
conflicts with planned outages.
The proposed revisions are intended to strengthen the collaboration and consultation
between the Reliability Coordinator and the Transmission Planner or Planning Coordinator at the
outset of determining the known outages that should be assessed in the Near-Term Transmission
Planning Horizon. In developing a comprehensive approach to the study of known outages in
Planning Assessments, and one that is flexible enough to accommodate the various outage
coordination processes in use across the North America, the TPL-001-5 standard drafting team
considered the Commission’s guidance in Order No. 786, the recommendations of the NERC
SAMS, feedback received during the standard development process, as well its own experience
and subject matter expertise.

59

Id. at P 40.

28

In proposed TPL-001-5, the provision relating to the assessment of known outages
(Requirement R1 Part 1.1.2) is struck from Requirement R1 and new provisions are added under
Requirement R2, Parts 2.1 and 2.4. These new provisions specify how analyses shall be assessed
and supported by studies. The relevant revisions to Requirement R2 are shown below:
R2.

Each Transmission Planner and Planning Coordinator shall
prepare an annual Planning Assessment of its portion of the
BES. This Planning Assessment shall use current or qualified
past studies (as indicated in Requirement R2, Part 2.6),
document assumptions, and document summarized results of the
steady state analyses, short circuit analyses, and Stability
analyses. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]
2.1.

For the Planning Assessment, the Near-Term Transmission
Planning Horizon portion of the steady state analysis shall
be assessed annually and be supported by current annual
studies or qualified past studies as indicated in Requirement
R2, Part 2.6. Qualifying studies need to include the
following conditions:

2.1.1. System peak Load for either Year One or year two, and
for year five.
2.1.2. System Off-Peak Load for one of the five years.
2.1.3. P1 events in Table 1, with known outages modeled as in
Requirement R1, Part 1.1.2, under those System peak or
Off-Peak conditions when known outages are scheduled.
***
2.1.4. 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
29

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
configuration such as those following P3 or P6 category
events in Table 1.
***
2.4.

For the Planning Assessment, the Near-Term Transmission
Planning Horizon portion of the Stability analysis shall be
assessed annually and be supported by current or past studies
as qualified in Requirement R2, Part 2.6. The following
studies are required:
***
2.4.4. 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 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, those 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
configuration such as those following P3 or P6 category
events in Table 1.
***

In proposed Reliability Standard TPL-001-5, the six month outage threshold is removed.
Planning entities would instead select known outages for study based on a documented
procedure or rationale that takes into account relevant factors, but does not exclude known
planned outages based solely on the outage duration. The change to where the assessment of

30

known outages is specified in the TPL-001-5 requirements better aligns the approach necessary
for the planning entities to execute their annual Planning Assessments. Further, the proposed
Requirement language recognizes the various means that Planning Coordinators and
Transmission Planners currently employ to consider the maintenance outages that could
potentially be of concern.
Under proposed Requirement R2 Parts 2.1.4 and 2.4.4., each Planning Coordinator and
Transmission Planner must have either a documented outage coordination procedure or technical
rationale to select which known outages shall be assessed as part of the steady state
(Requirement R2, Part 2.1.4) and Stability (Requirement R2, Part R2.4.4) analysis. The
documented outage coordination procedure would include consultation with the affected
Reliability Coordinator, consultation with Transmission and/or Generator Owner(s) affected by
the known outage, or application of documented outage coordination processes. The technical
rationale would include the well-reasoned technical bases for making the determination of which
known outages to assess.
Consistent with the intention of Order No. 786, the proposed provisions specify that an
entity shall not exclude known outages to be modeled based solely on the outage duration.
However, the presence of other accompanying factors, which in conjunction with outage
duration, may form a reasonable basis for supporting that the known outage need not be assessed
in the Near-Term Transmission Planning Horizon.
Under the proposed standard, an entity would be required to include, at a minimum, those
known outages expected to cause more severe System impacts, such as those that may result in
Non-Consequential Load Loss for the Table 1 Category P1 event. The Planning Coordinator and
Transmission Planner would have flexibility to use the appropriate means to assess which known

31

outages are expected to be significant, and to exclude from the assessment those outages which
the Planning Coordinator and Transmission Planner do not expect to be problematic. When
selecting those known outages for study, consideration must be paid to the System conditions,
such as On-Peak or Off-Peak, that are expected during the period when the known outage is
planned. The proposed standard provides that past or current studies may support the selection of
one or more known outages, if the past or current study or studies has comparable postContingency System conditions and configuration. For example, in many cases the Category P3
and P6 event study could result in the same System state as the Category P1 event with the
known outage. Such analysis, therefore, may be useful in helping to select which known outages
to study.
2. Spare Equipment Strategy for Stability Analysis
NERC also proposes revisions to address the Commission’s Order No. 786 directive to
consider adding provisions for spare equipment strategy as part of Stability analysis. In Order
No. 786, the Commission noted that TPL-001-4 Requirement R2 Part 2.1.5 requires that steady
state studies be performed for the P0, P1, and P2 categories identified in Table 1 with the
conditions that the system is expected to experience during the possible unavailability of the long
lead time equipment. The Commission stated that it believed that “a similar spare equipment
strategy for stability analysis should exist that requires studies to be performed for P0, P1 and P2
categories with the conditions that the system is expected to experience during the possible
unavailability of the long lead time equipment.” The Commission directed NERC to consider the
issue upon the next review cycle of TPL-001-4. 60

60

Order No. 786 at P 89.

32

Consistent with the Commission’s Order No. 786 guidance, the standard drafting team
revised the standard to add a similar requirement for Stability analysis, as follows:
2.4.

For the Planning Assessment, the Near-Term Transmission
Planning Horizon portion of the Stability analysis shall be
assessed annually and be supported by current or past studies
as qualified in Requirement R2, Part2.6. The following
studies are required:
***
2.4.5. When an entity’s spare equipment strategy could result
in the unavailability of major Transmission equipment
that has a lead time of one year or more (such as a
transformer), the impact of this possible unavailability
on System performance shall be assessed. Based upon
this assessment, an analysis shall be performed for the
selected P1 and P2 category events identified in Table 1
for which the unavailability is expected to produce more
severe System impacts on its portion of the BES. The
analysis shall simulate the conditions that the System is
expected to experience during the possible unavailability
of the long lead time equipment.

The addition of Requirement R2, Part 2.4.5, which includes similar language to that used
for the steady-state analysis under Requirement R2, Part 2.1.5, 61 clarifies that the outage of long
lead time Elements has an equally important impact from a Stability standpoint as it does from a
steady-state standpoint and should be assessed commensurate with an entity’s spare equipment
strategy. While the language in the two provisions is similar, there are two important differences.
First, the Category P0 event is not included because it is implied in the study. The nature
of Stability analysis is to observe the System dynamic response during and after a disturbance.
The Category P0 event conditions represent the undisturbed, initial, “normal” state of the
System. Given that initial System conditions for each long-lead time Element that is removed
from service are identical between steady state and Stability analyses, the Stability analysis of

61

Corresponding editorial changes are proposed in Requirement R2, Part 2.1.5, as shown in Exhibit A.

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the P0 event is implicitly assessed when conducting the steady state analysis of the P0 event.
Similarly, the prerequisite for conducting the Category P1 and P2 event Stability analysis is a
System model that incorporates and is initialized as the undisturbed (P0) state of the System.
Therefore, Category P0 is redundant and is appropriately omitted from Requirement R2 Part
2.4.5.
Second, proposed Reliability Standard TPL-001-5 Requirement R2 Part 2.4.5 provides
that “an analysis shall be performed for the selected P1 and P2 category events identified in
Table 1 for which the unavailability is expected to produce more severe System impacts on its
portion of the BES.” The dynamic response of the System and its ability to meet performance
requirements are expected to be more stressed for certain Category P1 and P2 category events,
topologically close to where the long-lead time Element is removed from service. Consistent
with Requirement R3 Part 3.4, those Category P1 and P2 events expected to produce more
severe System impacts are selected for Stability analysis. Additionally, prior testing and
knowledge of system performance can help to limit Stability testing to the relevant limiting
events.
C.

Other Revisions

Proposed Reliability Standard TPL-001-5 also contains several other revisions not
specifically highlighted above. First, the reference to the MOD-010 and MOD-012 standard in
Requirement R1 is replaced with a reference to the MOD-032 standard, which now contains the
relevant Requirements. 62 Second, references to “Special Protection System” have been replaced
with “Remedial Action Scheme,” consistent with previously-approved revisions to those defined

62

The Commission approved Reliability Standard MOD-032-1 and the retirement of Reliability Standards
MOD-010-0 and MOD-012-0 in 2014. See N. Am. Elec. Reliability Corp., Docket No. RD14-5-000 (May 1, 2014)
(delegated letter order).

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terms. 63 Lastly, a series of moves and formatting changes have been made to conform the
standard to the current NERC standard template. These proposed changes are shown in redline in
Exhibit A.
D.

Enforceability of the Proposed Reliability Standard

The proposed Reliability Standard contains Violation Risk Factors (“VRFs”) and
Violation Severity Levels (“VSLs”) for each of the standard’s Requirements. The VRFs and
VSLs provide guidance on the way that NERC will enforce the Requirements of the proposed
Reliability Standard. The VRFs and VSLs are substantively unchanged from currently effective
Reliability Standard TPL-001-4 and continue to comport with NERC and Commission
guidelines related to their assignment.
In addition, the proposed Reliability Standard also includes Measures that support the
Requirements by clearly identifying what is required and how the Requirement will be enforced.
The Measures, which are unchanged from currently-enforceable Reliability Standard TPL-001-4,
helps ensure that the Requirements will be enforced in a clear, consistent, and non-preferential
manner and without prejudice to any party.
EFFECTIVE DATE
NERC respectfully requests that the Commission approve the proposed implementation
plan attached to this Petition as Exhibit B. Under the proposed implementation plan, Reliability
Standard TPL-001-5 would become effective on the first day of the first calendar quarter that is

63

In 2016, the Commission approved the revised definition of Remedial Action Scheme. See Revisions to
Emergency Operations Reliability Standards; Revisions to Undervoltage Load Shedding Reliability Standards;
Revisions to the Definition of “Remedial Action Scheme” and Related Reliability Standards, Order No. 818, 153
FERC ¶ 61,228, at PP 24, 31 (2015). In 2016, the Commission approved the revised definition of Special Protection
System, to have the same meaning of Remedial Action Scheme. See N. Am. Elec. Reliability Corp., Docket No.
RD16-5-000 (June 23, 2016) (delegated letter order).

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36 months after regulatory approval. Reliability Standard TPL-001-4 would be retired
immediately prior to the effective date of TPL-001-5.
Under the TPL-001-5 implementation plan, entities have additional time to come into
compliance with certain Requirements related to the study of single points of failure on
Protection Systems. Specifically, planning entities would have an additional 24 months after the
effective date of the standard to develop Corrective Action Plans under Requirement R2, Part 2.7
for the Table 1 Category P5 planning event involving the non-redundant components of a
Protection System specified in Footnote 13 items a, b, c, and d. Further, entities shall have an
additional 72 months after the effective date of the standard to comply with the underlined part
of Requirement R2, Part 2.7 that states: “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.”
As explained in Exhibit B, the proposed implementation plan recognizes that Planning
Coordinators and Transmission Planners will need time to develop a procedure or technical
rationale for selecting known outages for study and for completing those planning studies.
Further, the implementation plan recognizes that Planning Coordinators and Transmission
Planners would need to engage in a substantial amount of work and coordination with asset
owners and protection engineers to perform the new Protection System single points of failure
studies and to coordinate on appropriate Corrective Action Plan measures and timetables to
address System performance issues. This is especially true in cases where Corrective Action
Plans may call for adding redundant Protection System components.
The proposed implementation plan recognizes the importance of ensuring that the
potential risks of known outages and Protection System single points of failure are being

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addressed in planning studies. Based upon the considerations described above, the proposed
implementation plan also provides a reasonable period of time for entities to come into
compliance with the proposed standard. For these reasons, NERC respectfully requests that the
Commission approve the proposed implementation plan.
CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission
approve:
•

proposed Reliability Standard TPL-001-5 and associated elements included in
Exhibit A;

•

the implementation plan included in Exhibit B; and

•

the retirement of currently effective Reliability Standard TPL-001-4.

Respectfully submitted,
/s/ Lauren A. Perotti
Lauren A. Perotti
Counsel
North American Electric Reliability Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099– facsimile
[email protected]
Counsel for the North American Electric
Reliability Corporation
December 7, 2018

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