NERC Petition

NERC Petition RM12-1 and RM13-9.pdf

FERC-725N, (Final Rule in RM12-1 & RM13-9) Mandatory Reliability Standards: Reliability Standard TPL-001-4

NERC Petition

OMB: 1902-0264

⚠️ Notice: This form may be outdated. More recent filings and information on OMB 1902-0264 can be found here:

Document [pdf]

Download: pdf | pdf

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

NORTH AMERICAN ELECTRIC
RELIABILITY CORPORATION

)
)

Docket Nos. RM13-_____
RM12-1-000

Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability Corporation
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326-1001
Tel: (404) 446-2560
Fax: (404) 446-2595

Charles A. Berardesco
Senior Vice President and General
Counsel
Holly A. Hawkins
Assistant General Counsel
North American Electric Reliability
Corporation
1325 G Street, NW, Suite 600
Washington, DC 20005-3132
Tel: (202) 400-3000
Fax: (202) 644-8099
charles.berardesco@nerc.net
holly.hawkins@nerc.net
Counsel for North American Electric
Reliability Corporation

February 28, 2013

TABLE OF CONTENTS
I.

Executive Summary ...................................................................................................................5

II.

Notices and Communications ....................................................................................................6

III. Background .................................................................................................................................7
A. Regulatory Framework ........................................................................................................7
B. NERC Reliability Standards Development Procedure ........................................................9
C. Procedural History of the TPL Standards ............................................................................9

IV.

Summary of the TPL Reliability Standards Development Proceedings .............................13
A. Overview of the Standard Drafting Team ..........................................................................13
B. Post-Order No. 762 Development History.........................................................................14
C. Board of Trustees Approval ...............................................................................................14

Footnote Requirements and Processes, Enforceability, and Improvements ......................15
A. Footnote Requirements and Processes ...............................................................................15
B. Enforceability of the TPL Standards; VRFs and VSLs Unchanged ..................................20
C. Improvements Reflected in the Proposed Standards .........................................................21

VI.

Requested Effective Dates .......................................................................................................21

VII. Conclusion .................................................................................................................................22
Exhibit A — Proposed Consolidated TPL Reliability Standard submitted for Approval
Exhibit B — Implementation Plan for the Consolidated TPL Reliability Standard
Exhibit C — Proposed Individual TPL Reliability Standards submitted for Approval
Exhibit D — Implementation Plans for the Individual TPL Reliability Standards
Exhibit E — Order No. 672 Criteria
Exhibit F — Results of Section 1600 Data Request
Exhibit G — Summary of Proposed TPL Standards Development Authorization, Posting, and
Balloting History
Exhibit H — Consideration of Comments
Exhibit I — Comprehensive Development Record
Exhibit J — Standard Drafting Team Roster for NERC Standards Development Project 2011-10

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

NORTH AMERICAN ELECTRIC
RELIABILITY CORPORATION

)
)

Docket Nos. RM13-_____
RM12-1-000

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF
MODIFIED TRANSMISSION PLANNING RELIABILITY STANDARDS
IN THE CASE OF
SYSTEM PERFORMANCE FOLLOWING LOSS OF A SINGLE BULK
ELECTRIC SYSTEM ELEMENT
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”) 1 and Section
39.5 of the Federal Energy Regulatory Commission’s (“FERC” or the “Commission”)
regulations, 18 C.F.R.§ 39.5 (2012), and in response to the Commission’s remand in
Order No. 762 2 (the “Remand”) and concerns identified in the Commission’s Notice of
Proposed Rulemaking issued in Docket No. RM12-1-000, 3 the North American Electric
Reliability Corporation (“NERC”) 4 hereby requests Commission approval of the
following changes to the requirements and processes for planned load shed in the event of
a single Contingency that are identified in a revised footnote, 5 and Attachment 1 to that

16 U.S.C. § 824o (2006).
Transmission Planning Reliability Standards, Order No. 762, 139 FERC ¶ 61,060 (2012).
(“Order No. 762”), order on reconsideration, 140 FERC ¶ 61,101 (2012).
3
Transmission Planning Reliability Standards, 139 FERC ¶ 61,059 (2012) (“TPL NOPR”).
4
The Commission certified NERC as the Electric Reliability Organization (“ERO”) in
accordance with Section 215 of the Federal Power Act pursuant on July 20, 2006 in Docket No. RR06-1000. North American Electric Reliability Corp., 116 FERC ¶ 61,062 (2006) (“ERO Certification Order”).
5
Capitalized terms used but not defined in this Petition are intended to have the same meaning
given to such terms in the Proposed Standards or the Glossary of Terms Used in NERC Reliability
Standards, available at: http://www.nerc.com/files/Glossary_of_Terms.pdf.
2

footnote (the “Footnote”). 6 NERC is also requesting Commission approval of revisions
to the Standards that correspond to the Footnote revisions included in this Petition and
other related documents:
•

Pursuant to the TPL NOPR, NERC is requesting approval of the proposed
TPL Standard TPL-001-4 (referred to herein as the “Consolidated TPL
Standard”) that was filed with the Commission as TPL-001-2 on October 19,
2011 in Docket No. RM12-1-000 and is currently pending approval (Exhibit
A).

•

Implementation Plan for the Consolidated TPL Standard that was filed
with the Commission on October 19, 2011 in Docket No. RM12-1-000 and is
currently pending approval (Exhibit B).

•

The proposed definitions included in the Consolidated TPL Standard that
were filed with the Commission on October 19, 2011 in Docket No. RM12-1000 and are currently pending approval (included in Exhibit A).

•

The proposed Violation Risk Factors (“VRFs”) and Violation Severity
Levels (“VSLs”) for the Consolidated TPL Standard that were filed with
Commission for approval on October 19, 2011 in Docket No. RM12-1-000
and are currently pending approval (included in Exhibit A).

•

Retirement of the following Reliability Standards (the currently-effective
versions of the individual TPL standards (collectively, the “Current TPL
Standards”)), concurrently with the effectiveness of the proposed TPL-001-4
Reliability Standard:

•



TPL-001-0.1;



TPL-002-0b;



TPL-003-0a; and



TPL-004-0.

The withdrawal of two pending TPL Reliability Standards, TPL-005-0 (Regional
and Interregional Self-Assessment Reliability Reports) and TPL-006-0.1 (Data
from the Regional Reliability Organization Needed to Assess Reliability)
because the requirements from these Reliability Standards have been moved to
Sections 803 and 804 of the NERC Rules of Procedure. These proposed

Footnote ‘b’ included as part of TPL-002-2b is in all material respects the same as the proposed
footnote 12 included as part of Reliability Standard TPL-001-4.

withdrawals were addressed in NERC’s October 19, 2011 petition filed in FERC
Docket No. RM12-1-000.
The Consolidated TPL Standard supersedes the Current TPL Standards by
consolidating the four Version 0 TPL standards (TPL-001-0.1; TPL-002-0b; TPL-003-0a;
and TPL-004-0) into the proposed Consolidated TPL Standard. The Consolidated TPL
Standard includes the proposed Footnote as Note 12, which is the only addition to the
Consolidated TPL Standard since it was initially filed with FERC for approval on
October 19, 2011.
In the event the Commission does not approve the Consolidated TPL Standard,
NERC requests approval of the following:
•

Pursuant to the Remand, four Proposed Transmission Planning (“TPL”)
Reliability Standards (together, the “Individual TPL Standards”):


TPL-001-3 ((System Performance Under Normal (No
Contingency) Conditions (Category A))) (Exhibit C);



TPL-002-2b (System Performance Following Loss of a Single
Bulk Electric System Element (Category B)) (Exhibit C);



TPL-003-2a (System Performance Following Loss of Two or
More Bulk Electric System Elements (Category C)) (Exhibit C);



TPL-004-2 (System Performance Following Extreme Events
Resulting in the Loss of Two or More Bulk Electric System
Elements (Category D)) (Exhibit C).

•

Implementation Plan for TPL-001-3, TPL-002-2b, TPL-003-2a, and
TPL-004-2 (Exhibit D).

•

Retirement of the following Reliability Standards concurrently with the
effectiveness of its corresponding Individual TPL Standard:


TPL-001-0.1;



TPL-002-0b;



TPL-003-0a; and



TPL-004-0.

Collectively, the Consolidated TPL Standard and the Individual TPL Standards are referred
to herein as the “Proposed TPL Standards”.

EXECUTIVE SUMMARY
The limited but critical change to the Proposed TPL Standards and the purpose of

this petition is to revise the Footnote to address concerns articulated by the Commission,
most recently in Order No. 762 and the concurrently issued TPL NOPR. As described in
greater detail in Section V of this petition, and the supporting materials included with this
petition, the Footnote provides specific parameters for the permissible use of planned
shedding of Firm Demand to address Bulk Electric System (“BES”) performance issues,
including:
•

Firm limitations on the maximum amount of load that may be planned to
be shed,

•

Safeguards to ensure against inconsistent results and arbitrary
determinations that allow for the planned shedding of Firm Demand, and

•

A more specifically defined, open and transparent, verifiable, and
enforceable stakeholder process designed to ensure that there will be no
Adverse Reliability Impacts caused by a request to plan for Firm Demand
interruption, subject in certain cases to a final review by the ERO.

The Footnote was developed in accordance with Section 300 of NERC’s Rules of
Procedure (Reliability Standards Development) and the NERC Standard Processes
Manual. The NERC Board of Trustees approved the Footnote and its inclusion in the
Proposed TPL Standards on February 7, 2013.

As revised, the Footnote and the Proposed TPL Standards will improve reliability
by providing specific procedural and substantive parameters for the proposed stakeholder
process, defining the circumstances in which a plan for non-consequential load loss could
be utilized, and establishing safeguards to ensure against inconsistent results and arbitrary
determinations in the case of planned interruption of Firm Demand.

II.

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

following: 7
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability Corporation
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326-1001
Tel: (404) 446-2560
Fax: (404) 446-2595

Charles A. Berardesco*
Senior Vice President and General Counsel
Holly A. Hawkins*
Assistant General Counsel
North American Electric Reliability Corporation
1325 G Street, NW, Suite 600
Washington, DC 20005-3132
Tel: (202) 400-3000
Fax: (202) 644-8099– facsimile
charles.berardesco@nerc.net
holly.hawkins@nerc.net

Persons to be included on the Commission’s service list are identified by an asterisk.

III.

GENERAL BACKGROUND
Provided below are the following: (a) an explanation of the regulatory

background for NERC Reliability Standards; (b) an explanation of the NERC Reliability
Standards development procedure; and (c) the procedural history of the TPL Reliability
Standards.
A. Regulatory Framework

By enacting the Energy Policy Act of 2005, 8 Congress entrusted the Commission
with the duties of approving and enforcing rules to ensure the reliability of the nation’s
Bulk Power System, 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 of the FPA states that all users, owners, and operators of the BulkPower System in the United States will be subject to Commission-approved Reliability
Standards. 9
Section 215(d)(5) of the FPA authorizes the Commission to order the ERO to
submit a new or modified Reliability Standard for the Commission’s review and
approval. However, FPA Section 215(c)(2)(D) requires the ERO to develop that
standard, using “a process that provides for reasonable notice and opportunity for public
comment, due process, openness, and balance of interests.” 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

16 U.S.C. § 824o (2006).
See Section 215(b)(1)(“All users, owners and operators of the bulk-power system shall comply
with reliability standards that take effect under this section.”).
9

the content of a Reliability Standard. In Order No. 693, 10 the Commission noted that it
would defer to the “technical expertise” of the ERO with respect to the content of a
Reliability Standard and explained that, through the use of directives, it provides
guidance, but does not dictate an outcome. Further, it stated that the Commission will
consider an alternative approach to a Commission proposal, example or directive,
provided that the ERO demonstrates that the alternative will address the Commission’s
underlying concern or goal as efficiently and effectively as the Commission’s proposal,
example, or directive. 11
Section 39.5(a) of the Commission’s regulations requires the ERO to request the
Commission’s approval for each new Reliability Standard that the ERO proposes to
become mandatory and enforceable in the United States, as well as each modification to
an existing Reliability Standard that the ERO proposes to be made effective. 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.
Order No. 672 12 provides guidance on the factors the Commission will consider
when determining whether proposed Reliability Standards meet the statutory criteria to
ensure that they are just, reasonable, not unduly discriminatory or preferential, and in the
public interest. Each of those factors is addressed in Exhibit E.
10

Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. &
Regs. ¶ 31,242 (“Order No. 693”), order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).
11
See Order No. 693 at PP 31, 186-187.
12
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 (2006).

B. NERC Reliability Standards Development Procedure

NERC develops Reliability Standards in accordance with Section 300 (Reliability
Standards Development) of its Rules of Procedure and the NERC Standard Processes
Manual. In its ERO Certification Order, 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 and thus satisfies
certain of the criteria for approving Reliability Standards. The development process is
open to any person or entity with a legitimate interest in the reliability of the Bulk Power
System. NERC considers the comments of all stakeholders, and a vote of stakeholders
and the NERC Board of Trustees is required to approve a Reliability Standard before the
Reliability Standard is submitted to the Commission for approval. The Footnote and its
inclusion in the Proposed TPL Standards were approved by the NERC Board of Trustees
on February 7, 2013.
C. Procedural History of the TPL Standards
1. Order No. 693 Directive

Each of the Current TPL Standards was first approved by the Commission in
Order No. 693, which approved 83 of 107 Reliability Standards filed by NERC. In
approving the Reliability Standards, the Commission directed modifications to 56 of the
Reliability Standards, including modifications to the TPL Standards. Pertinent to this
petition, the Commission stated that TPL Standards should not allow an entity to plan for
the loss of non-consequential firm load in the event of a single Contingency. 13

Order 693 at P 1794.

Accordingly, the Commission directed NERC to develop certain modifications to the
TPL Standards, including a clarification to the Footnote.
In a subsequent order, however, the Commission clarified that a regional
difference in a plan for the loss of firm service would be acceptable, but only in limited
circumstances, or in a specific case for which there is technical justification. 14
Specifically, the Commission stated that “a regional difference, or a case-specific
exception process that can be technically justified, to plan for the loss of firm service at
the fringes of various systems would be an acceptable approach.” 15 In the June 2010
Order, the Commission granted NERC an extension of time, to March 31, 2011, to
submit a modification to TPL-002-0 responsive to the Commission’s directive in Order
No. 693. 16
2. Order No. 762 Remand

On March 31, 2011, NERC filed a petition for approval of revisions to the Current
TPL Standards, specifically intended to clarify the Footnote as directed in Order No. 693
(the “March 2011 Filing”). However, in response to the March 2011 Filing, the
Commission concluded, in Order No. 762, that the proposed revisions to the Footnote did
not meet the Commission’s Order No. 693 directives, nor did the revisions achieve “an
equally effective and efficient alternative”. 17 Accordingly, the Commission remanded
the March 2011 Filing to NERC, directing NERC to revise TPL-002-1b (the Footnote) to
address the Commission’s concerns described in Order No. 762, subject to the additional
14

Mandatory Reliability Standards for the Bulk Power System, 131 FERC ¶ 61,231, at P 21
(2010) (“June 2010 Order”).
15
Id.
16
Id. at P 26.
17
Order No. 762 at P 12.

guidance provided therein. 18 In response to a NERC request for reconsideration, 19 the
Commission permitted NERC to address the Commission’s concerns using NERC’s
regular process for developing Reliability Standards, rather than by invoking NERC’s
Expedited Standards Development Process, based on NERC’s commitment to deliver a
new Footnote to the NERC Board of Trustees for a vote at the Board’s February 2013
meeting. 20
Additionally, in Order No. 762, the Commission directed NERC to “identify the
specific instances of any planned interruptions of Firm Demand under footnote “b” and
how frequently the provision has been used.” 21 FERC directed NERC to use Section
1600 of its Rules of Procedure to obtain information from users, owners, and operators of
the Bulk Power System to provide this requested data and to submit the information to
FERC with this petition.22 Accordingly, the summary results of the Section 1600 Data
Request (“Data Request”) on the instances of footnote b use under the Current TPL
Standards are included as Exhibit F to this petition.
NERC recognizes that because the Footnote proposed in this filing is different
from the footnote b included in the existing TPL standards, data does not yet exist on the
frequency of instances of planned interruption of Firm Demand under the new Footnote.
For this reason, NERC is committing to monitor use of the Footnote and will report the
results of this monitoring after the first two years of the Footnote’s implementation.

Id. at P 66.
Request of the North American Electric Reliability Corporation for Reconsideration, or in the
Alternative, Rehearing of Order Remanding the Transmission Planning Reliability Standards, Docket No.
RM11-18-000 (May 21, 2012).
20
Transmission Planning Reliability Standards, 140 FERC ¶ 61,101 at P 6 (2012).
21
Order No. 762 at P 20.
22
Id.
19

3. Notice of Proposed Rulemaking – Consolidated TPL Standard

In matters related to the Footnote, NERC filed a petition on October 19, 2011 in
Docket No. RM12-1, seeking approval of the Consolidated TPL Standard that combines
the four Current TPL Standards into a single standard (i.e., filed as TPL-001-2 and
included in this petition as TPL-001-4), as well as approval of an associated
implementation plan, VRFs, and VSLs, and five new definitions to be added to the
NERC Glossary of Terms. NERC also requested approval of the retirement of the four
Current TPL Standards and the withdrawal of two pending TPL Standards. 23 The
proposed TPL-001-2 included the Footnote that was the subject of the Remand, which
was adapted for the new standard without modifying the technical content and intent of
the Footnote, and which was subject to ongoing consideration and refinement in Project
2010-11 (TPL Table 1 Order Project). 24 In light of the inclusion of the Footnote,
however, and “notwithstanding improvements contained in other provisions of TPL-0012”, the Commission issued the TPL NOPR, indicating that it had “no option other than to
propose to remand the entire Reliability Standard [TPL-001-2]”. 25 The Commission
added, however, that “resolution of this one matter will allow the industry, NERC and the
Commission to go forward with the consideration of other improvements contained in

The pending TPL Standards are TPL-005-0 (Regional and Interregional Self-Assessment
Reliability Reports) and TPL-006-0.1 (Data from the Regional Reliability Organization Needed to Assess
Reliability). The requirements from these Standards have been moved to Section 803 and 804 of the
NERC Rules of Procedure.
24
Project 2011-10 addressed Commission orders that which required NERC to clarify the
Footnote.
25
TPL NOPR at P 2.

proposed Reliability Standard TPL-001-2.” 26 The TPL NOPR and TPL-001-2 remain
pending before the Commission. It is for this reason that NERC has included the
proposed revisions to the Consolidated TPL Standard that are intended to replace the
proposed TPL-001-2 standard pending with the Commission, the proposed revisions to
the Individual TPL Standards to be approved in the event the Consolidated TPL Standard
is not approved, and the documents corresponding to the Proposed TPL Standards with
this petition to revise the Footnote.

IV.

SUMMARY OF THE TPL RELIABILITY STANDARDS DEVELOPMENT
PROCEEDINGS
The highlights of the development process for the proposed Footnote to be

included in both the Consolidated TPL Standard and the Individual TPL Standards are
summarized below. Exhibit G contains a Summary of the Development Authorization,
Posting, and Balloting History of the Footnote and the Proposed Standards since the
Remand. Exhibit H contains the Consideration of Comments Reports created during the
development of the Proposed Standards post-Order 762. Exhibit I contains the complete
post-Order No. 762 record of development for the Proposed Standards.
A. Overview of the Standard Drafting Team

When evaluating modified Reliability Standards, the Commission is expected to
give “due weight” to the technical expertise of the ERO. 27 The technical expertise of the
ERO is derived from the Standard Drafting Team (“Drafting Team”). For this project,
the Drafting Team consisted of 14 industry experts with a wealth of diverse industry
26
27

Id. at P 3.
FPA § 215(d)(2); 16 U.S.C. § 824o(d)(2) (2012).

experience across North America, including both the continental United States and
Canada. A Drafting Team roster and member biographical information is included in
Exhibit J.
B. Post-Order No. 762 Development History

In response to Order No. 762 and the TPL NOPR, the Standards Committee
directed the Drafting Team to respond quickly to directives in those orders, as well as the
prior directives in Order No. 693, to address planned load shed under limited
circumstances for single Contingencies. The Footnote was revised to meet those
directives, as well as to comments received following four rounds of public comment and
three rounds of balloting, which concluded when the January 2013 recirculation ballot
achieved a quorum of 88.55% and a weighted stakeholder segment approval of 69.63%. 28
C. Board of Trustees Approval

The final drafts of the stakeholder-approved Proposed TPL Standards, each of
which contains the Footnote revised in response to the Remand, together with a NERC
staff summary of the revisions, underlying history, minority issues and associated
Drafting Team responses, and additional background information, were presented to
NERC’s Board of Trustees for approval on February 7, 2013. The Board of Trustees
approved the revisions to the Footnote incorporated into the Proposed TPL Standards,
and directed NERC staff to make the requisite filings with applicable regulatory
authorities.

See Exhibit G to this petition.

FOOTNOTE REQUIREMENTS AND PROCESSES, ENFORCEABILITY, AND
IMPROVEMENTS
Provided below are the following: (a) an explanation of the Footnote Requirements

and processes; (b) an explanation of the enforceability of the TPL Reliability Standards; and
(c) an explanation of the improvements included in the Proposed Standards.
A. Footnote Requirements and Processes

1. Proposed Stakeholder Process
The Footnote’s stakeholder process is well defined by specific parameters and
required information sharing. The main body of the Footnote states that the objective of
the planning process is to minimize the likelihood and magnitude of interruption of Firm
Demand following Contingency events, while describing the conditions that would be
allowed for dropping non-consequential load and meeting the overarching threshold
value for any planned load shed, as set forth in the Footnote.
Section I of Attachment 1 to the Footnote sets forth the conditions that must be
satisfied to establish open and transparent stakeholder meetings, which is the first step an
entity must meet in invoking use of the Footnote. Section I also details who must be
invited, the process for notifying interested parties, what information must be supplied to
them, a process for presenting stakeholder questions and concerns, and a method for
resolving disputes. The stakeholder meetings must be held for any circumstance for
which the planned utilization of the Footnote would be applicable. Further, based on the
data provided in response to the Data Request, the standard drafting team determined that
a planned load shed up to 25 MW should be resolved within the described stakeholder
process with no further review required.

Section I also provides that an entity does not have to repeat the stakeholder
process for a specific application of the Footnote with respect to subsequent Planning
Assessments unless conditions spelled out in Section II have materially changed for that
specific application. This language was intentionally included to be consistent with
Requirement R2.6 of the Consolidated TPL standard, which allows for past studies to be
used to support Planning Assessments if they meet certain conditions, including for
steady state, short circuit, or Stability analysis, when no material changes occur to the
System.
Similarly, in the proposed Footnote, in order to lessen the burden on industry, if
conditions in which the Footnote is utilized have not materially changed for that specific
application, the Drafting Team determined that the entity should not have to repeat the
stakeholder process required under the proposed Footnote. This approach builds in
flexibility and allows entities to use operating judgment in determining what constitutes a
“material change” (e.g., thereby allowing the entity to take into account regional and
operating differences).
The proposed Requirement R8 of the Consolidated TPL Standard includes an
additional safeguard to monitoring Planning Assessments by requiring that Planning
Assessments be shared with adjacent Planning Coordinators, Transmission Planners, or
other entities that demonstrate a reliability related need. Requirement R8 provides:
Each Planning Coordinator and Transmission Planner shall distribute its Planning
Assessment results to adjacent Planning Coordinators and adjacent Transmission
Planners within 90 calendar days of completing its Planning 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. [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]

Requirement R8 of the Consolidated TPL Standard therefore provides a system of checks
and balances on entities’ Planning Assessments from neighboring entities in the overall
transmission planning process of which the proposed Footnote is one small part.
Additionally, in Order No. 762, FERC asked how the ERO would determine the
cumulative effect of load shedding if there is no annual review of load shedding under the
Footnote due to the lack of a material change. Use of the Footnote itself is not
representative of every instance of possible planned load shed because multiple
contingency situations, for example, allow load shed under certain circumstances.
However, Requirement R8 of the proposed Consolidated TPL Standard, described above,
should help enable peer oversight of what is contained in the assessments. This will give
Planning Coordinators, Transmission Planners, and other entities the ability to monitor
any potential cumulative effect of load shedding.
Section II of Attachment 1 specifies the information that has to be provided to
stakeholders with respect to the purpose and scope of the proposed Firm Demand
interruption under the Footnote. This information is designed to adequately demonstrate
to stakeholders why and how the load shed alternative was selected as the best planning
choice, while allowing stakeholders to see all of the variables that were involved in
selecting the load shed alternative, including costs, frequency, and duration of the
planned load shed, mitigation plans, explanation of the effect on public health, safety, and
welfare, and adherence to the transmission planning performance standards and the
Footnote.
Section III of Attachment 1 describes the process for planned load shed greater
than 25 MW. Specifically, planned load sheds between 25 MW and 75 MW, or any

planned load shed at the 300 kV level or above would receive greater scrutiny by
regulatory authorities and the ERO. The 300 kV voltage level is based on the previously
submitted Extra High Voltage (“EHV”) level that had been proposed in TPL-001-2 which
raised the bar for transmission planning for such EHV facilities. The 75 MW limit was
derived from information received in response to the Data Request and is the maximum
amount of planned load shed allowed by the Footnote for U.S. entities. Importantly,
system performance after utilization of the footnote must continue to meet transmission
planning performance standards, which do not allow for instability, uncontrolled
separation, or cascading failures.
2. Circumstances in which Non-Consequential Load Loss may be
Allowed
As noted above, the proposed Footnote provides specific limitations on how much
non-consequential load a responsible entity can plan to shed for a single Contingency
event, while defining the terms and conditions under which such planned load shed could
be justified – in an open and transparent public forum. The Data Request results provide
the technical basis for establishing the load shed amount limitations. In addition, the
Footnote sets out what information must be provided to the affected stakeholders to
enable them to consider the costs associated with the proposed plans, as well as any
alternatives. The combination of amount limitations and other considerations, such as
costs and alternatives, guards against a determination based solely on a quantitative
threshold becoming an acceptable de facto interpretation of planned Firm Demand.
Therefore, the procedures in the Footnote would enable acceptable, but limited,

circumstances of planned Firm Demand interruptions after a thorough stakeholder review
and approval and, in some cases, ERO review.
3. Safeguards Against Inconsistent Results and Arbitrary
Determinations
To ensure against inconsistent results and arbitrary determinations, the Footnote
requires that, subject to defined thresholds (voltage level of Contingency greater than 300
kV or a planned interruption greater than or equal to 25 MW), entities with regulatory
oversight over retail electric service that would be affected by a Firm Demand
interruption (“Retail Regulator”) must agree to the use of the Footnote. Once the Retail
Regulator has indicated that it does not object to the Firm Demand interruption under the
Footnote, the responsible entity must submit the Section II information included in the
stakeholder process to the ERO. The ERO then must determine whether or not there are
any Adverse Reliability Impacts caused by the request to use the Footnote, thus meeting
the ERO’s review and oversight function. 29
The ERO’s oversight role will be focused on determining whether there are any
Adverse Reliability Impacts. “Adverse Reliability Impact” is defined in the NERC
Glossary of Terms as “[t]he impact of an event that results in frequency-related
instability; unplanned tripping of load or generation; or uncontrolled separation or
cascading outages that affects a widespread area of the Interconnection.” Consistent with
this definition, NERC’s oversight of uses of the Footnote that exceed a voltage level
greater than 300 kV or a planned interruption greater than or equal to 25 MW will be

The proposed Footnote preserves, to the extent practicable, the role of Retail Regulators. The
Footnote limits the ERO’s role in local planning process, but still allows the ERO to review possible
Adverse Reliability Impacts.

focused on whether any of the conditions included in the definition of Adverse Reliability
Impact are met.
B. Enforceability of the TPL Standards; VRFs and VSLs Unchanged

The proposed TPL Standards include measures that support each Reliability
Standard requirement, by clearly identifying what is required and how the requirement
will be enforced, thus ensuring that the requirements will be enforced in a clear,
consistent, and non-preferential manner, and without prejudice to any party. 30 In
addition, the revised Footnote, in providing specific parameters for the permissible use of
planned shedding of Firm Demand, ensures against inconsistent results and arbitrary
determinations. The Footnote accomplishes this by providing a defined, open and
transparent, verifiable, and enforceable stakeholder process that ensures there are no
Adverse Reliability Impacts on the BES. The VSLs also provide further guidance on
how the ERO will enforce the requirements of the Standard.
The proposed VRFs and VSLs for the Consolidated TPL Standard were included
in the petition filed with the Commission for approval on October 19, 2011. NERC
hereby requests Commission approval of those VRFs and VSLs in response to this
petition. As noted above, in the event the Commission does not approve the
Consolidated TPL Standard, NERC is requesting Commission approval of the Individual
TPL Standards as modified to include the Footnote. The Individual TPL Standards do

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

not modify the Commission-approved VRFs and VSLs included in the Current TPL
Standards.
C. Improvements Reflected in the Proposed Standards

As discussed in more detail above, the Footnote addresses the Commission’s
concerns raised in Order No. 762 and the TPL NOPR. The proposed revision to the
Footnote is an equally effective and efficient alternative to address the Commission’s
directive that must be given due consideration by the Commission. The Proposed TPL
Standards would improve reliability by:

VI.

•

Providing a blend of specific quantitative and qualitative parameters for the
permissible use of planned shedding of Firm Demand to address BES
performance issues;

•

Providing a clear and concise definition of the process, including specific
criteria and guidelines, that must be followed before a responsible entity may
plan to shed load in the event of a single Contingency; and

•

Providing additional safeguards to ensure that there will be no Adverse
Reliability Impacts caused by a request to plan for Firm Demand interruption.

REQUESTED EFFECTIVE DATES
As noted above, NERC requests that each of the Proposed TPL Standards become

effective in accordance with the effective date provisions contained therein. NERC
further requests that the Commission approve the retirement of the Current TPL
Standards upon approval of the proposed Consolidated TPL Standard, or alternatively,
upon approval of the proposed Individual TPL Standards. The corresponding proposed
effective dates are just and reasonable and appropriately balance the urgency in the need
to implement the Footnote in the Proposed TPL Standards against the reasonableness of

the time allowed for those who must comply to develop the necessary procedures and
take the necessary actions to reflect the requirements and processes identified in the
Footnote. The proposed effective dates will allow affected entities adequate time to
ensure compliance with the Footnote in accordance with Order No. 672. 31

VII.

CONCLUSION
Accordingly, and for the reasons set forth above, NERC respectfully requests that

the Commission approve:
•

the Proposed TPL Standards included in Exhibits A and C, effective as
proposed therein and as described in this filing;

•

the Implementation Plans included in Exhibits B and D as described in this
filing; and

•

the retirement of the Current TPL Standards concurrent with approval of
either the proposed Consolidated TPL Standard or the Individual TPL
Standards.

Order No. 672 at P 333, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212
(2006) (“In considering whether a proposed Reliability Standard is just and reasonable, FERC 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.”).

Respectfully submitted,
/s/ Holly A. Hawkins
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability Corporation
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326-1001
Tel: (404) 446-2560
Fax: (404) 446-2595

Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Assistant General Counsel
North American Electric Reliability
Corporation
1325 G Street, NW, Suite 600
Washington, DC 20005-3132
Tel: (202) 400-3000
Fax: (202) 644-8099
charles.berardesco@nerc.net
holly.hawkins@nerc.net
Counsel for North American Electric
Reliability Corporation

CERTIFICATE OF SERVICE
I hereby certify that I have served a copy of the foregoing document upon all parties
listed on the official service list compiled by the Secretary in this proceeding.
Dated at Washington, D.C. this 28th day of February, 2013.
/s/ Holly A. Hawkins
Holly A. Hawkins
Attorney for North American
Electric Reliability Corporation

Exhibit A
Proposed Consolidated TPL Reliability Standard submitted for Approval

Standard TPL-001-4 — Transmission System Planning Performance Requirements

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements

Number:

Purpose:
Establish Transmission system planning performance requirements within the
planning horizon to develop a Bulk Electric System (BES) that will operate reliably over a
broad spectrum of System conditions and following a wide range of probable Contingencies.

Applicability:

TPL-001-4

4.1. Functional Entity

4.1.1.

Planning Coordinator.

4.1.2.

Transmission Planner.

Effective Date: Requirements R1 and R7 as well as the definitions shall become effective on
the first day of the first calendar quarter, 12 months after applicable regulatory approval. In
those jurisdictions where regulatory approval is not required, Requirements R1 and R7 become
effective on the first day of the first calendar quarter, 12 months after Board of Trustees
adoption or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
Except as indicated below, Requirements R2 through R6 and Requirement R8 shall become
effective on the first day of the first calendar quarter, 24 months after applicable regulatory
approval. In those jurisdictions where regulatory approval is not required, all requirements,
except as noted below, go into effect on the first day of the first calendar quarter, 24 months
after Board of Trustees adoption or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
For 84 calendar months beginning the first day of the first calendar quarter following applicable
regulatory approval, or in those jurisdictions where regulatory approval is not required on the
first day of the first calendar quarter 84 months after Board of Trustees adoption or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities, Corrective Action Plans applying to the following categories of Contingencies and
events identified in TPL-001-4, Table 1 are allowed to include Non-Consequential Load Loss
and curtailment of Firm Transmission Service (in accordance with Requirement R2, Part 2.7.3.)
that would not otherwise be permitted by the requirements of TPL-001-4:










P1-2 (for controlled interruption of electric supply to local network customers
connected to or supplied by the Faulted element)
P1-3 (for controlled interruption of electric supply to local network customers
connected to or supplied by the Faulted element)
P2-1
P2-2 (above 300 kV)
P2-3 (above 300 kV)
P3-1 through P3-5
P4-1 through P4-5 (above 300 kV)
P5 (above 300 kV)

Standard TPL-001-4 — Transmission System Planning Performance Requirements

B. Requirements
R1.

Each Transmission Planner and Planning Coordinator shall maintain System models within its
respective area for performing the studies needed to complete its Planning Assessment. The
models shall use data consistent with that provided in accordance with the MOD-010 and
MOD-012 standards, supplemented by other sources as needed, including items represented in
the Corrective Action Plan, and shall represent projected System conditions. This establishes
Category P0 as the normal System condition in Table 1. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning]
1.1.

R2.

System models shall represent:
1.1.1.

Existing Facilities

1.1.2.

Known outage(s) of generation or Transmission Facility(ies) with a duration
of at least six months.

1.1.3.

New planned Facilities and changes to existing Facilities

1.1.4.

Real and reactive Load forecasts

1.1.5.

Known commitments for Firm Transmission Service and Interchange

1.1.6.

Resources (supply or demand side) required for Load

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: Long-term 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.

For each of the studies described in Requirement R2, Parts 2.1.1 and 2.1.2,
sensitivity case(s) shall be utilized to demonstrate the impact of changes to
the basic assumptions used in the model. To accomplish this, the sensitivity
analysis in the Planning Assessment must vary one or more of the following
conditions by a sufficient amount to stress the System within a range of
credible conditions that demonstrate a measurable change in System
response :






Real and reactive forecasted Load.
Expected transfers.
Expected in service dates of new or modified Transmission Facilities.
Reactive resource capability.
Generation additions, retirements, or other dispatch scenarios.

Standard TPL-001-4 — Transmission System Planning Performance Requirements

2.1.5.

2.2.



Controllable Loads and Demand Side Management.



Duration or timing of known Transmission outages.

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 studied. The studies shall 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.

For the Planning Assessment, the Long-Term Transmission Planning Horizon portion
of the steady state analysis shall be assessed annually and be supported by the
following annual current study, supplemented with qualified past studies as indicated
in Requirement R2, Part 2.6:
2.2.1.

A current study assessing expected System peak Load conditions for one of
the years in the Long-Term Transmission Planning Horizon and the rationale
for why that year was selected.

2.3.

The short circuit analysis portion of the Planning Assessment shall be conducted
annually addressing the Near-Term Transmission Planning Horizon and can be
supported by current or past studies as qualified in Requirement R2, Part 2.6. The
analysis shall be used to determine whether circuit breakers have interrupting
capability for Faults that they will be expected to interrupt using the System short
circuit model with any planned generation and Transmission Facilities in service
which could impact the study area.

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:
2.4.1.

System peak Load for one of the five years. System peak Load levels shall
include a Load model which represents the expected dynamic behavior of
Loads that could impact the study area, considering the behavior of induction
motor Loads. An aggregate System Load model which represents the overall
dynamic behavior of the Load is acceptable.

2.4.2.

System Off-Peak Load for one of the five years.

2.4.3.

For each of the studies described in Requirement R2, Parts 2.4.1 and 2.4.2,
sensitivity case(s) shall be utilized to demonstrate the impact of changes to
the basic assumptions used in the model. To accomplish this, the sensitivity
analysis in the Planning Assessment must vary one or more of the following
conditions by a sufficient amount to stress the System within a range of
credible conditions that demonstrate a measurable change in performance:






Load level, Load forecast, or dynamic Load model assumptions.
Expected transfers.
Expected in service dates of new or modified Transmission Facilities.
Reactive resource capability.
Generation additions, retirements, or other dispatch scenarios.

Standard TPL-001-4 — Transmission System Planning Performance Requirements

2.5.

For the Planning Assessment, the Long-Term Transmission Planning Horizon portion
of the Stability analysis shall be assessed to address the impact of proposed material
generation additions or changes in that timeframe and be supported by current or past
studies as qualified in Requirement R2, Part2.6 and shall include documentation to
support the technical rationale for determining material changes.

2.6.

Past studies may be used to support the Planning Assessment if they meet the
following requirements:

2.7.

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.

For planning events shown in Table 1, when the analysis indicates an inability of the
System to meet the performance requirements in Table 1, the Planning Assessment
shall include Corrective Action Plan(s) 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. Corrective Action Plan(s) do not need to be developed solely
to meet the performance requirements for a single sensitivity case analyzed in
accordance with Requirements R2, Parts 2.1.4 and 2.4.3. The Corrective Action
Plan(s) shall:
2.7.1.

List System deficiencies and the associated actions needed to achieve
required System performance. Examples of such actions include:



Installation, modification, retirement, or removal of Transmission and
generation Facilities and any associated equipment.



Installation, modification, or removal of Protection Systems or Special
Protection Systems



Installation or modification of automatic generation tripping as a
response to a single or multiple Contingency to mitigate Stability
performance violations.



Installation or modification of manual and automatic generation
runback/tripping as a response to a single or multiple Contingency to
mitigate steady state performance violations.



Use of Operating Procedures specifying how long they will be needed
as part of the Corrective Action Plan.



Use of rate applications, DSM, new technologies, or other initiatives.

2.7.2.

Include actions to resolve performance deficiencies identified in multiple
sensitivity studies or provide a rationale for why actions were not necessary.

2.7.3.

Standard TPL-001-4 — Transmission System Planning Performance Requirements

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.
2.7.4.

2.8.

R3.

Be reviewed in subsequent annual Planning Assessments for continued
validity and implementation status of identified System Facilities and
Operating Procedures.

For short circuit analysis, if the short circuit current interrupting duty on circuit
breakers determined in Requirement R2, Part 2.3 exceeds their Equipment Rating, the
Planning Assessment shall include a Corrective Action Plan to address the Equipment
Rating violations. The Corrective Action Plan shall:
2.8.1.

List System deficiencies and the associated actions needed to achieve
required System performance.

2.8.2.

Be reviewed in subsequent annual Planning Assessments for continued
validity and implementation status of identified System Facilities and
Operating Procedures.

For the steady state portion of the Planning Assessment, each Transmission Planner and
Planning Coordinator shall perform studies for the Near-Term and Long-Term Transmission
Planning Horizons in Requirement R2, Parts 2.1, and 2.2. The studies shall be based on
computer simulation models using data provided in Requirement R1. [Violation Risk Factor:
Medium] [Time Horizon: Long-term Planning]
3.1.

Studies shall be performed for planning events to determine whether the BES meets
the performance requirements in Table 1 based on the Contingency list created in
Requirement R3, Part 3.4.

3.2.

Studies shall be performed to assess the impact of the extreme events which are
identified by the list created in Requirement R3, Part 3.5.

3.3.

Contingency analyses for Requirement R3, Parts 3.1 & 3.2 shall:
3.3.1.

3.3.2.

3.4.

Simulate the removal of all elements that the Protection System and other
automatic controls are expected to disconnect for each Contingency without
operator intervention. The analyses shall include the impact of subsequent:
3.3.1.1.

Tripping of generators where simulations show generator bus
voltages or high side of the generation step up (GSU) voltages
are less than known or assumed minimum generator steady state
or ride through voltage limitations. Include in the assessment
any assumptions made.

3.3.1.2.

Tripping of Transmission elements where relay loadability limits
are exceeded.

Simulate the expected automatic operation of existing and planned devices
designed to provide steady state control of electrical system quantities when
such devices impact the study area. These devices may include equipment
such as phase-shifting transformers, load tap changing transformers, and
switched capacitors and inductors.

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
5

Standard TPL-001-4 — Transmission System Planning Performance Requirements

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.
3.4.1.

3.5.

R4.

The Planning Coordinator and Transmission Planner shall coordinate with
adjacent Planning Coordinators and Transmission Planners to ensure that
Contingencies on adjacent Systems which may impact their Systems are
included in the Contingency list.

Those extreme events in Table 1 that are expected to produce more severe System
impacts shall be identified and a list created of those events to be evaluated in
Requirement R3, Part 3.2. The rationale for those Contingencies selected for
evaluation shall be available as supporting information. 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.

For the Stability portion of the Planning Assessment, as described in Requirement R2, Parts 2.4
and 2.5, each Transmission Planner and Planning Coordinator shall perform the Contingency
analyses listed in Table 1. The studies shall be based on computer simulation models using
data provided in Requirement R1.
[Violation Risk Factor: Medium] [Time Horizon: Longterm Planning]
4.1.

Studies shall be performed for planning events to determine whether the BES meets
the performance requirements in Table 1 based on the Contingency list created in
Requirement R4, Part 4.4.
4.1.1.

For planning event P1: No generating unit shall pull out of synchronism. A
generator being disconnected from the System by fault clearing action or by
a Special Protection System is not considered pulling out of synchronism.

4.1.2.

For planning events P2 through P7: When a generator pulls out of
synchronism in the simulations, the resulting apparent impedance swings
shall not result in the tripping of any Transmission system elements other
than the generating unit and its directly connected Facilities.

4.1.3.

For planning events P1 through P7: Power oscillations shall exhibit
acceptable damping as established by the Planning Coordinator and
Transmission Planner.

4.2.

Studies shall be performed to assess the impact of the extreme events which are
identified by the list created in Requirement R4, Part 4.5.

4.3.

Contingency analyses for Requirement R4, Parts 4.1 and 4.2 shall :
4.3.1.

4.3.1.2.

Successful high speed (less than one second) reclosing and
unsuccessful high speed reclosing into a Fault where high speed
reclosing is utilized.
Tripping of generators where simulations show generator bus
voltages or high side of the GSU voltages are less than known or
assumed generator low voltage ride through capability. Include
in the assessment any assumptions made.

Standard TPL-001-4 — Transmission System Planning Performance Requirements

4.3.1.3.

4.3.2.

4.4.

Simulate the expected automatic operation of existing and planned devices
designed to provide dynamic control of electrical system quantities when
such devices impact the study area. These devices may include equipment
such as generation exciter control and power system stabilizers, static var
compensators, power flow controllers, and DC Transmission controllers.

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 created of those
Contingencies to be evaluated in Requirement R4, Part 4.1. The rationale for those
Contingencies selected for evaluation shall be available as supporting information.
4.4.1.

4.5.

Tripping of Transmission lines and transformers where transient
swings cause Protection System operation based on generic or
actual relay models.

Each Planning Coordinator and Transmission Planner shall coordinate with
adjacent Planning Coordinators and Transmission Planners to ensure that
Contingencies on adjacent Systems which may impact their Systems are
included in the Contingency list.

Those extreme events in Table 1 that are expected to produce more severe System
impacts shall be identified and a list created of those events to be evaluated in
Requirement R4, Part 4.2. The rationale for those Contingencies selected for
evaluation shall be available as supporting information. 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 of the
event(s) shall be conducted.

R5.

Each Transmission Planner and Planning Coordinator shall have criteria for acceptable System
steady state voltage limits, post-Contingency voltage deviations, and the transient voltage
response for its System. 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]

R6.

Each Transmission Planner and Planning Coordinator shall define and document, within their
Planning Assessment, the criteria or methodology used in the analysis to identify System
instability for conditions such as Cascading, voltage instability, or uncontrolled islanding.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

R7.

Each Planning Coordinator, in conjunction with each of its Transmission Planners, shall
determine and identify each entity’s individual and joint responsibilities for performing the
required studies for the Planning Assessment. [Violation Risk Factor: Low] [Time Horizon:
Long-term Planning]

R8.

Each Planning Coordinator and Transmission Planner shall distribute its Planning Assessment
results to adjacent Planning Coordinators and adjacent Transmission Planners within 90
calendar days of completing its Planning 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. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
8.1.

If a recipient of the Planning Assessment results provides documented comments on
the results, the respective Planning Coordinator or Transmission Planner shall provide
a documented response to that recipient within 90 calendar days of receipt of those
comments.

Standard TPL-001-4 — Transmission System Planning Performance Requirements
Table 1 – Steady State & Stability Performance Planning Events
Steady State & Stability:
a.
b.
c.
d.

The System shall remain stable. Cascading and uncontrolled islanding shall not occur.
Consequential Load Loss as well as generation loss is acceptable as a consequence of any event excluding P0.
Simulate the removal of all elements that Protection Systems and other controls are expected to automatically disconnect for each event.
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.
g.
h.
i.

Applicable Facility Ratings shall not be exceeded.
System steady state voltages and post-Contingency voltage deviations shall be within acceptable limits as established by the Planning Coordinator and the Transmission
Planner.
Planning event P0 is applicable to steady state only.
The response of voltage sensitive Load that is disconnected from the System by end-user equipment associated with an event shall not be used to meet steady state
performance requirements.

Stability Only:
j. Transient voltage response shall be within acceptable limits established by the Planning Coordinator and the Transmission Planner.
Category
P0
No Contingency

P1
Single
Contingency

Fault Type 2

BES Level 3

Interruption of Firm
Transmission
Service Allowed 4

Non-Consequential
Load Loss Allowed

None

N/A

EHV, HV

Loss of one of the following:
1. Generator
2. Transmission Circuit
5
3. Transformer
6
4. Shunt Device

3Ø
EHV, HV

No9

No12

EHV, HV

No9

No12

EHV

No9

Yes

Event 1

Initial Condition

Normal System

5. Single Pole of a DC line
1.
P2
Single
Contingency

SLG

Opening of a line section w/o a fault

N/A

Bus Section Fault

SLG

Normal System
3. Internal Breaker Fault
(non-Bus-tie Breaker)

4. Internal Breaker Fault (Bus-tie Breaker)

EHV

Yes

EHV, HV

Yes

SLG
8

SLG

Standard TPL-001-4 — Transmission System Planning Performance Requirements
Category

P3
Multiple
Contingency

Initial Condition

Loss of generator unit
followed by System
adjustments9

Event

Loss of one of the following:
1. Generator
2. Transmission Circuit
5
3. Transformer
4. Shunt Device 6
5. Single pole of a DC line

P4
Multiple
Contingency
(Fault plus stuck
breaker10)

Normal System

Loss of multiple elements caused by a stuck
10
breaker (non-Bus-tie Breaker) attempting to
clear a Fault on one of the following:
1. Generator
2. Transmission Circuit
5
3. Transformer
6
4. Shunt Device
5. Bus Section
6. Loss of multiple elements caused by a
10
stuck breaker (Bus-tie Breaker)
attempting to clear a Fault on the
associated bus

P5
Multiple
Contingency
(Fault plus relay
failure to
operate)

Normal System

P6
Multiple
Contingency
(Two
overlapping
singles)

Loss of one of the
following followed by
9
System adjustments.
1. Transmission Circuit
5
2. Transformer
6
3. Shunt Device
4. Single pole of a DC line

Delayed Fault Clearing due to the failure of a
non-redundant relay13 protecting the Faulted
element to operate as designed, for one of
the following:
1. Generator
2. Transmission Circuit
5
3. Transformer
6
4. Shunt Device
5. Bus Section
Loss of one of the following:
1. Transmission Circuit
5
2. Transformer
3. Shunt Device 6
4. Single pole of a DC line

Fault Type 2

BES Level 3

Interruption of Firm
Transmission
Service Allowed 4

Non-Consequential
Load Loss Allowed

3Ø

EHV, HV

No9

No12

EHV

Yes

EHV, HV

Yes

EHV

Yes

EHV, HV

Yes

EHV, HV

Yes

SLG
9

SLG

3Ø

SLG

Standard TPL-001-4 — Transmission System Planning Performance Requirements
Category
P7
Multiple
Contingency
(Common
Structure)

Initial Condition

Normal System

Event

The loss of:
1. Any two adjacent (vertically or
horizontally) circuits on common
11
structure
2. Loss of a bipolar DC line

Fault Type 2

BES Level 3

Interruption of Firm
Transmission
Service Allowed 4

Non-Consequential
Load Loss Allowed

SLG

EHV, HV

Yes

Standard TPL-001-4 — Transmission System Planning Performance Requirements

Table 1 – Steady State & Stability Performance Extreme Events
Steady State & Stability
For all extreme events evaluated:
a. Simulate the removal of all elements that Protection Systems and automatic controls are expected to disconnect for each Contingency.
b. Simulate Normal Clearing unless otherwise specified.
Steady State
1. Loss of a single generator, Transmission Circuit, single pole of a DC
Line, shunt device, or transformer forced out of service followed by
another single generator, Transmission Circuit, single pole of a
different DC Line, shunt device, or transformer forced out of service
prior to System adjustments.
2. Local area events affecting the Transmission System such as:
a. Loss of a tower line with three or more circuits.11
b. Loss of all Transmission lines on a common Right-of-Way11.
c. Loss of a switching station or substation (loss of one voltage
level plus transformers).
d. Loss of all generating units at a generating station.
e. Loss of a large Load or major Load center.
3. Wide area events affecting the Transmission System based on
System topology such as:
a. Loss of two generating stations resulting from conditions such
as:
i. Loss of a large gas pipeline into a region or multiple
regions that have significant gas-fired generation.
ii. Loss of the use of a large body of water as the cooling
source for generation.
iii. Wildfires.
iv. Severe weather, e.g., hurricanes, tornadoes, etc.
v. A successful cyber attack.
vi. Shutdown of a nuclear power plant(s) and related
facilities for a day or more for common causes such
as problems with similarly designed plants.
b. Other events based upon operating experience that may
result in wide area disturbances.

Stability
1. With an initial condition of a single generator, Transmission circuit,
single pole of a DC line, shunt device, or transformer forced out of
service, apply a 3Ø fault on another single generator, Transmission
circuit, single pole of a different DC line, shunt device, or transformer
prior to System adjustments.
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.
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 internal breaker fault.
f. Other events based upon operating experience, such as
consideration of initiating events that experience suggests may
result in wide area disturbances

Standard TPL-001-4 — Transmission System Planning Performance Requirements

Table 1 – Steady State & Stability Performance Footnotes
(Planning Events and Extreme 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 stated performance criteria regarding allowances for interruptions of Firm Transmission Service and Non-Consequential Load Loss.
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. Bulk Electric System (BES) level references include extra-high voltage (EHV) Facilities defined as greater than 300kV and high voltage (HV) Facilities defined
as the 300kV and lower voltage Systems. The designation of EHV and HV is used to distinguish between stated performance criteria allowances for
interruption of Firm Transmission Service and Non-Consequential Load Loss.
4. Curtailment of Conditional Firm Transmission Service is allowed when the conditions and/or events being studied formed the basis for the Conditional Firm
Transmission Service.
5. 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.
6. Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
7. 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.
8. 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.
9. An objective of the planning process should be to minimize the likelihood and magnitude of interruption of Firm Transmission Service following Contingency
events. Curtailment of Firm Transmission Service is allowed both as a System adjustment (as identified in the column entitled ‘Initial Condition’) and a
corrective action when achieved through the appropriate re-dispatch of resources obligated to re-dispatch, where it can be demonstrated that Facilities,
internal and external to the Transmission Planner’s planning region, remain within applicable Facility Ratings and the re-dispatch does not result in any NonConsequential Load Loss. Where limited options for re-dispatch exist, sensitivities associated with the availability of those resources should be considered.
10. 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.
11. Excludes circuits that share a common structure (Planning event P7, Extreme event steady state 2a) or common Right-of-Way (Extreme event, steady state
2b) for 1 mile or less.
12. An objective of the planning process is to minimize the likelihood and magnitude of Non-Consequential Load Loss following planning events. In limited
circumstances, Non-Consequential Load Loss may be needed throughout the planning horizon to ensure that BES performance requirements are met.
However, when Non-Consequential Load Loss is utilized under footnote 12 within the Near-Term Transmission Planning Horizon to address BES
performance requirements, such interruption is limited to circumstances where the Non-Consequential Load Loss meets the conditions shown in Attachment
1. In no case can the planned Non-Consequential Load Loss under footnote 12 exceed 75 MW for US registered entities. The amount of planned NonConsequential Load Loss for a non-US Registered Entity should be implemented in a manner that is consistent with, or under the direction of, the applicable
governmental authority or its agency in the non-US jurisdiction.
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, &
12

Standard TPL-001-4 — Transmission System Planning Performance Requirements
Table 1 – Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)
67), and tripping (#86, & 94).

Standard TPL-001-4 — Transmission System Planning Performance Requirements

Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Non-Consequential Load Loss under
footnote 12 is allowed as an element of a Corrective Action Plan in the Near-Term Transmission
Planning Horizon of the Planning Assessment, the Transmission Planner or Planning
Coordinator shall ensure that the utilization of footnote 12 is reviewed through an open and
transparent stakeholder process. The responsible entity can utilize an existing process or develop
a new process. .The process must include the following:
1. Meetings must be open to affected stakeholders including applicable regulatory
authorities or governing bodies responsible for retail electric service issues
2. Notice must be provided in advance of meetings to affected stakeholders including
applicable regulatory authorities or governing bodies responsible for retail electric service
issues and include an agenda with:
a. Date, time, and location for the meeting
b. Specific location(s) of the planned Non-Consequential Load Loss under footnote
12
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed NonConsequential Load Loss under footnote 12 (as shown in Section II below) must be made
available to meeting participants
4. A procedure for stakeholders to submit written questions or concerns and to receive
written responses to the submitted questions and concerns
5. A dispute resolution process for any question or concern raised in #4 above that is not
resolved to the stakeholder’s satisfaction
An entity does not have to repeat the stakeholder process for a specific application of footnote 12
utilization with respect to subsequent Planning Assessments unless conditions spelled out in
Section II below have materially changed for that specific application.
II. Information for Inclusion in Item #3 of the Stakeholder Process
The responsible entity shall document the planned use of Non-Consequential Load Loss under
footnote 12 which must include the following:
1. Conditions under which Non-Consequential Load Loss under footnote 12 would be
necessary:
a. System Load level and estimated annual hours of exposure at or above that Load
level
b. Applicable Contingencies and the Facilities outside their applicable rating due to
that Contingency
2. Amount of Non-Consequential Load Loss with:
a. The estimated number and type of customers affected

Standard TPL-001-4 — Transmission System Planning Performance Requirements

3.
4.
5.
6.
7.
8.

b. An explanation of the effect of the use of Non-Consequential Load Loss under
footnote 12 on the health, safety, and welfare of the community
Estimated frequency of Non-Consequential Load Loss under footnote 12 based on
historical performance
Expected duration of Non-Consequential Load Loss under footnote 12 based on historical
performance
Future plans to alleviate the need for Non-Consequential Load Loss under footnote 12
Verification that TPL Reliability Standards performance requirements will be met
following the application of footnote 12
Alternatives to Non-Consequential Load Loss considered and the rationale for not
selecting those alternatives under footnote 12
Assessment of potential overlapping uses of footnote 12 including overlaps with adjacent
Transmission Planners and Planning Coordinators

III. Instances for which Regulatory Review of Non-Consequential Load Loss under Footnote 12
is Required
Before a Non-Consequential Load Loss under footnote 12 is allowed as an element of a
Corrective Action Plan in Year One of the Planning Assessment, 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 if either:
1. The voltage level of the Contingency is greater than 300 kV
a. If the Contingency analyzed involves BES Elements at multiple System voltage
levels, the lowest System voltage level of the element(s) removed for the
analyzed Contingency determines the stated performance criteria regarding
allowances for Non-Consequential Load Loss under footnote 12, or
b. For a non-generator step up transformer outage Contingency, the 300 kV limit
applies to the low-side winding (excluding tertiary windings). For a generator or
generator step up transformer outage Contingency, the 300 kV limit applies to the
BES connected voltage (high-side of the Generator Step Up transformer)
2. The planned Non-Consequential Load Loss under footnote 12 is greater than or equal to
25 MW
Once assurance has been received 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, the Planning Coordinator or Transmission Planner must submit the
information outlined in items II.1 through II.8 above to the ERO for a determination of whether
there are any Adverse Reliability Impacts caused by the request to utilize footnote 12 for NonConsequential Load Loss.

Standard TPL-001-4 — Transmission System Planning Performance Requirements

C. Measures
M1. Each Transmission Planner and Planning Coordinator shall provide evidence, in electronic or
hard copy format, that it is maintaining System models within their respective area, using data
consistent with MOD-010 and MOD-012, including items represented in the Corrective Action
Plan, representing projected System conditions, and that the models represent the required
information in accordance with Requirement R1.
M2. Each Transmission Planner and Planning Coordinator shall provide dated evidence, such as
electronic or hard copies of its annual Planning Assessment, that it has prepared an annual
Planning Assessment of its portion of the BES in accordance with Requirement R2.
M3. Each Transmission Planner and Planning Coordinator shall provide dated evidence, such as
electronic or hard copies of the studies utilized in preparing the Planning Assessment, in
accordance with Requirement R3.
M4. Each Transmission Planner and Planning Coordinator shall provide dated evidence, such as
electronic or hard copies of the studies utilized in preparing the Planning Assessment in
accordance with Requirement R4.
M5. Each Transmission Planner and Planning Coordinator shall provide dated evidence such as
electronic or hard copies of the documentation specifying the criteria for acceptable System
steady state voltage limits, post-Contingency voltage deviations, and the transient voltage
response for its System in accordance with Requirement R5.
M6. Each Transmission Planner and Planning Coordinator shall provide dated evidence, such as
electronic or hard copies of documentation specifying the criteria or methodology used in the
analysis to identify System instability for conditions such as Cascading, voltage instability, or
uncontrolled islanding that was utilized in preparing the Planning Assessment in accordance
with Requirement R6.
M7. Each Planning Coordinator, in conjunction with each of its Transmission Planners, shall
provide dated documentation on roles and responsibilities, such as meeting minutes,
agreements, and e-mail correspondence that identifies that agreement has been reached on
individual and joint responsibilities for performing the required studies and Assessments in
accordance with Requirement R7.
M8. Each Planning Coordinator and Transmission Planner shall provide evidence, such as email
notices, documentation of updated web pages, postal receipts showing recipient and date; or a
demonstration of a public posting, that it has distributed its Planning Assessment results to
adjacent Planning Coordinators and adjacent Transmission Planners within 90 days of having
completed its Planning Assessment, and to any functional entity who has indicated a reliability
need within 30 days of a written request and that the Planning Coordinator or Transmission
Planner has provided a documented response to comments received on Planning Assessment
results within 90 calendar days of receipt of those comments in accordance with Requirement
R8.
D. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
Regional Entity
1.2 Compliance Monitoring Period and Reset Timeframe
Not applicable.

Standard TPL-001-4 — Transmission System Planning Performance Requirements

1.3 Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4 Data Retention
The Transmission Planner and Planning Coordinator shall each retain data or evidence to
show compliance as identified unless directed by its Compliance Enforcement Authority
to retain specific evidence for a longer period of time as part of an investigation:


The models utilized in the current in-force Planning Assessment and one
previous Planning Assessment in accordance with Requirement R1 and Measure
M1.



The Planning Assessments performed since the last compliance audit in
accordance with Requirement R2 and Measure M2.



The studies performed in support of its Planning Assessments since the last
compliance audit in accordance with Requirement R3 and Measure M3.



The studies performed in support of its Planning Assessments since the last
compliance audit in accordance with Requirement R4 and Measure M4.



The documentation specifying the criteria for acceptable System steady state
voltage limits, post-Contingency voltage deviations, and transient voltage
response since the last compliance audit in accordance with Requirement R5 and

Measure M5.



The documentation specifying the criteria or methodology utilized in the analysis
to identify System instability for conditions such as Cascading, voltage
instability, or uncontrolled islanding in support of its Planning Assessments since
the last compliance audit in accordance with Requirement R6 and Measure M6.



The current, in force documentation for the agreement(s) on roles and
responsibilities, as well as documentation for the agreements in force since the
last compliance audit, in accordance with Requirement R7 and Measure M7.

The Planning Coordinator shall retain data or evidence to show compliance as identified
unless directed by its Compliance Enforcement Authority to retain specific evidence for a
longer period of time as part of an investigation:


Three calendar years of the notifications employed in accordance with
Requirement R8 and Measure M8.

If a Transmission Planner or Planning Coordinator is found non-compliant, it shall keep
information related to the non-compliance until found compliant or the time periods
specified above, whichever is longer.
1.5 Additional Compliance Information
None

Standard TPL-001-4 — Transmission System Planning Performance Requirements

2. Violation Severity Levels

Lower VSL

Moderate VSL

High VSL

The responsible entity’s System
model failed to represent one of the
Requirement R1, Parts 1.1.1
through 1.1.6.

The responsible entity’s System
model failed to represent two of the
Requirement R1, Parts 1.1.1 through
1.1.6.

The responsible entity’s System
model failed to represent three of the
Requirement R1, Parts 1.1.1 through
1.1.6.

Severe VSL
The responsible entity’s System model
failed to represent four or more of the
Requirement R1, Parts 1.1.1 through
1.1.6.
OR
The responsible entity’s System model
did not represent projected System
conditions as described in Requirement
R1.
OR
The responsible entity’s System model
did not use data consistent with that
provided in accordance with the MOD010 and MOD-012 standards and other
sources, including items represented in
the Corrective Action Plan.

The responsible entity failed to
comply with Requirement R2, Part
2.6.

The responsible entity failed to
comply with Requirement R2, Part 2.3
or Part 2.8.

The responsible entity failed to
comply with one of the following
Parts of Requirement R2: Part 2.1,
Part 2.2, Part 2.4, Part 2.5, or Part
2.7.

The responsible entity failed to comply
with two or more of the following Parts
of Requirement R2: Part 2.1, Part 2.2,
Part 2.4, or Part 2.7.
OR
The responsible entity does not have a
completed annual Planning
Assessment.

The responsible entity did not
identify planning events as
described in Requirement R3, Part
3.4 or extreme events as described
in Requirement R3, Part 3.5.

The responsible entity did not perform
studies as specified in Requirement
R3, Part 3.1 to determine that the
BES meets the performance
requirements for one of the categories
(P2 through P7) in Table 1.

The responsible entity did not
perform studies as specified in
Requirement R3, Part 3.1 to
determine that the BES meets the
performance requirements for two of
the categories (P2 through P7) in

The responsible entity did not perform
studies as specified in Requirement R3,
Part 3.1 to determine that the BES
meets the performance requirements
for three or more of the categories (P2
through P7) in Table 1.

Standard TPL-001-4 — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

Table 1.

The responsible entity did not perform
studies as specified in Requirement
R3, Part 3.2 to assess the impact of
extreme events.

The responsible entity did not perform
studies to determine that the BES
meets the performance requirements
for the P0 or P1 categories in Table 1.

The responsible entity did not
perform Contingency analysis as
described in Requirement R3, Part
3.3.

OR
The responsible entity did not base its
studies on computer simulation models
using data provided in Requirement R1.

The responsible entity did not
identify planning events as
described in Requirement R4, Part
4.4 or extreme events as described
in Requirement R4, Part 4.5.

The responsible entity did not perform
studies as specified in Requirement
R4, Part 4.1 to determine that the
BES meets the performance
requirements for one of the categories
(P1 through P7) in Table 1.
OR
The responsible entity did not perform
studies as specified in Requirement
R4, Part 4.2 to assess the impact of
extreme events.

The responsible entity did not
perform studies as specified in
Requirement R4, Part 4.1 to
determine that the BES meets the
performance requirements for two of
the categories (P1 through P7) in
Table 1.
OR
The responsible entity did not
perform Contingency analysis as
described in Requirement R4, Part
4.3.

The responsible entity did not perform
studies as specified in Requirement R4,
Part 4.1 to determine that the BES
meets the performance requirements
for three or more of the categories (P1
through P7) in Table 1.
OR
The responsible entity did not base its
studies on computer simulation models
using data provided in Requirement R1.

N/A

The responsible entity does not have
criteria for acceptable System steady
state voltage limits, post-Contingency
voltage deviations, or the transient
voltage response for its System.

N/A

The responsible entity failed to define
and document the criteria or
methodology for System instability used
within its analysis as described in
Requirement R6.

Standard TPL-001-4 — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

N/A

The Planning Coordinator, in
conjunction with each of its
Transmission Planners, failed to
determine and identify individual or joint
responsibilities for performing required
studies.

The responsible entity distributed its
Planning Assessment results to
adjacent Planning Coordinators and
adjacent Transmission Planners but
it was more than 90 days but less
than or equal to 120 days following
its completion.

The responsible entity distributed its
Planning Assessment results to
adjacent Planning Coordinators and
adjacent Transmission Planners but it
was more than 120 days but less than
or equal to 130 days following its
completion.

The responsible entity distributed its
Planning Assessment results to
adjacent Planning Coordinators and
adjacent Transmission Planners but
it was more than 130 days but less
than or equal to 140 days following
its completion.

The responsible entity distributed its
Planning Assessment results to
adjacent Planning Coordinators and
adjacent Transmission Planners but it
was more than 140 days following its
completion.

OR,

The responsible entity distributed its
Planning Assessment results to
functional entities having a reliability
related need who requested the
Planning Assessment in writing but
it was more than 30 days but less
than or equal to 40 days following
the request.

The responsible entity distributed its
Planning Assessment results to
functional entities having a reliability
related need who requested the
Planning Assessment in writing but it
was more than 40 days but less than
or equal to 50 days following the
request.

The responsible entity distributed its
Planning Assessment results to
functional entities having a reliability
related need who requested the
Planning Assessment in writing but it
was more than 50 days but less than
or equal to 60 days following the
request.

OR
The responsible entity did not distribute
its Planning Assessment results to
adjacent Planning Coordinators and
adjacent Transmission Planners.
OR
The responsible entity distributed its
Planning Assessment results to
functional entities having a reliability
related need who requested the
Planning Assessment in writing but it
was more than 60 days following the
request.
OR
The responsible entity did not distribute
its Planning Assessment results to
functional entities having a reliability
related need who requested the
Planning Assessment in writing.

Standard TPL-001-4 — Transmission System Planning Performance Requirements

Regional Variances
None.

Version History
Version

Date

Action

Change Tracking

April 1, 2005

Effective Date

New

February 8, 2005

BOT Approval

Revised

June 3, 2005

Fixed reference in M1 to read TPL-001-0 R2.1
and TPL-001-0 R2.2

Errata

July 24, 2007

Corrected reference in M1. to read TPL-001-0
R1 and TPL-001-0 R2.

Errata

0.1

October 29, 2008

BOT adopted errata changes; updated version number
to “0.1”

Errata

0.1

May 13, 2009

FERC Approved – Updated Effective Date and Footer

Revised

1 Approved
by
Board of Trustees
February 17, 2011

Revised footnote ‘b’ pursuant to FERC Order RM0616-009

Revised (Project 201011)

August 4, 2011

Revision of TPL-001-1; includes merging and
upgrading requirements of TPL-001-0, TPL-002-0,
TPL-003-0, and TPL-004-0 into one, single,
comprehensive, coordinated standard: TPL-001-2; and
retirement of TPL-005-0 and TPL-006-0.

Project 2006-02 –
complete revision

August 4, 2011

Adopted by Board of Trustees

April 19, 2012

FERC issued Order 762 remanding TPL-001-1, TPL002-1b, TPL-003-1a, and TPL-004-1. FERC also
issued a NOPR proposing to remand TPL-001-2.
NERC has been directed to revise footnote 'b' in
accordance with the directives of Order Nos. 762 and
693.

February 7, 2013

Adopted by the NERC Board of Trustees.
TPL-001-3 was created after the Board of Trustees
approved the revised footnote ‘b’ in TPL-002-2b,
which was balloted and appended to: TPL-001-0.1,
TPL-002-0b, TPL-003-0a, and TPL-004-0.

February 7, 2013

Adopted by the NERC Board of Trustees.
TPL-001-4 was adopted by the Board of Trustees as
TPL-001-3, but a discrepancy in numbering was
identified and corrected prior to filing with the
regulatory agencies.

Standard TPL-001-24 — Transmission System Planning Performance Requirements

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements

Number:

Applicability:

TPL-001-24

4.1. Functional Entity

4.1.1.

Planning Coordinator.

4.1.2.

Transmission Planner.

Requirements R1 and R7 as well as the definitions shall become
Effective Date:
effective on the first day of the first calendar quarter, 12 months after applicable regulatory
approval. In those jurisdictions where no regulatory approval is not required, Requirements R1
and R7 become effective on the first day of the first calendar quarter, 12 months after Board of
Trustees adoption. or as otherwise made effective pursuant to the laws applicable to such
ERO governmental authorities.
Except as indicated below, Requirements R2 through R6 and Requirement R8 shall become
effective on the first day of the first calendar quarter, 24 months after applicable regulatory
approval. In those jurisdictions where no regulatory approval is not required, all requirements,
except as noted below, go into effect on the first day of the first calendar quarter, 24 months
after Board of Trustees adoption or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
For 84 calendar months beginning the first day of the first calendar quarter following applicable
regulatory approval, or in those jurisdictions where no regulatory approval is not required on
the first day of the first calendar quarter 84 months after Board of Trustees adoption or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities, Corrective Action Plans applying to the following categories of Contingencies and
events identified in TPL-001-24, Table 1 are allowed to include Non-Consequential Load Loss
and curtailment of Firm Transmission Service (in accordance with Requirement R2, Part 2.7.3.)
that would not otherwise be permitted by the requirements of TPL-001-24:











Adopted by NERC Board of Trustees: August 4, 2011

Standard TPL-001-24 — Transmission System Planning Performance Requirements

B. Requirements
R1.

R2.

System models shall represent:
1.1.1.

Existing Facilities

1.1.2.

Known outage(s) of generation or Transmission Facility(ies) with a duration
of at least six months.

1.1.3.

New planned Facilities and changes to existing Facilities

1.1.4.

Real and reactive Load forecasts

1.1.5.

Known commitments for Firm Transmission Service and Interchange

1.1.6.

Resources (supply or demand side) required for Load

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.

Adopted by NERC Board of Trustees: August 4, 2011

Standard TPL-001-24 — Transmission System Planning Performance Requirements

2.1.5.

2.2.



Controllable Loads and Demand Side Management.



Duration or timing of known Transmission outages.

A current study assessing expected System peak Load conditions for one of
the years in the Long-Term Transmission Planning Horizon and the rationale
for why that year was selected.

2.3.

2.4.

2.4.2.

System Off-Peak Load for one of the five years.

2.4.3.

Adopted by NERC Board of Trustees: August 4, 2011

Standard TPL-001-24 — Transmission System Planning Performance Requirements

2.5.

2.6.

Past studies may be used to support the Planning Assessment if they meet the
following requirements:

2.7.

2.6.1.

2.6.2.

List System deficiencies and the associated actions needed to achieve
required System performance. Examples of such actions include:



Installation, modification, retirement, or removal of Transmission and
generation Facilities and any associated equipment.



Installation, modification, or removal of Protection Systems or Special
Protection Systems



Installation or modification of automatic generation tripping as a
response to a single or multiple Contingency to mitigate Stability
performance violations.



Installation or modification of manual and automatic generation
runback/tripping as a response to a single or multiple Contingency to
mitigate steady state performance violations.



Use of Operating Procedures specifying how long they will be needed
as part of the Corrective Action Plan.



Use of rate applications, DSM, new technologies, or other initiatives.

2.7.2.

Include actions to resolve performance deficiencies identified in multiple
sensitivity studies or provide a rationale for why actions were not necessary.

2.7.3.

Adopted by NERC Board of Trustees: August 4, 2011

Standard TPL-001-24 — Transmission System Planning Performance Requirements

2.8.

R3.

Be reviewed in subsequent annual Planning Assessments for continued
validity and implementation status of identified System Facilities and
Operating Procedures.

List System deficiencies and the associated actions needed to achieve
required System performance.

2.8.2.

Be reviewed in subsequent annual Planning Assessments for continued
validity and implementation status of identified System Facilities and
Operating Procedures.

Studies shall be performed for planning events to determine whether the BES meets
the performance requirements in Table 1 based on the Contingency list created in
Requirement R3, Part 3.4.

3.2.

Studies shall be performed to assess the impact of the extreme events which are
identified by the list created in Requirement R3, Part 3.5.

3.3.

Contingency analyses for Requirement R3, Parts 3.1 & 3.2 shall:
3.3.1.

3.3.2.

3.4.

3.3.1.2.

Tripping of Transmission elements where relay loadability limits
are exceeded.

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

Adopted by NERC Board of Trustees: August 4, 2011

Standard TPL-001-24 — Transmission System Planning Performance Requirements

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.
3.4.1.

3.5.

R4.

Studies shall be performed for planning events to determine whether the BES meets
the performance requirements in Table 1 based on the Contingency list created in
Requirement R4, Part 4.4.
4.1.1.

4.1.2.

4.1.3.

For planning events P1 through P7: Power oscillations shall exhibit
acceptable damping as established by the Planning Coordinator and
Transmission Planner.

4.2.

Studies shall be performed to assess the impact of the extreme events which are
identified by the list created in Requirement R4, Part 4.5.

4.3.

Contingency analyses for Requirement R4, Parts 4.1 and 4.2 shall :
4.3.1.

4.3.1.2.

Adopted by NERC Board of Trustees: August 4, 2011

Standard TPL-001-24 — Transmission System Planning Performance Requirements

4.3.1.3.

4.3.2.

4.4.

4.5.

Tripping of Transmission lines and transformers where transient
swings cause Protection System operation based on generic or
actual relay models.

R5.

R6.

R7.

R8.

Adopted by NERC Board of Trustees: August 4, 2011

Standard TPL-001-24 — Transmission System Planning Performance Requirements

Adopted by NERC Board of Trustees: August 4, 2011

Standard TPL-001-24 — Transmission System Planning Performance Requirements
Table 1 – Steady State & Stability Performance Planning Events
Steady State & Stability:
a.
b.
c.
d.

Stability Only:
j. Transient voltage response shall be within acceptable limits established by the Planning Coordinator and the Transmission Planner.
Category
P0
No Contingency

P1
Single
Contingency

Fault Type 2

BES Level 3

Interruption of Firm
Transmission
Service Allowed 4

Non-Consequential
Load Loss Allowed

None

N/A

EHV, HV

Loss of one of the following:
1. Generator
2. Transmission Circuit
5
3. Transformer
6
4. Shunt Device

3Ø
EHV, HV

No9

No12

EHV, HV

No9

No12

EHV

No9

Yes

Event 1

Initial Condition

Normal System

5. Single Pole of a DC line
1.
P2
Single
Contingency

SLG

Opening of a line section w/o a fault

N/A

Bus Section Fault

SLG

Normal System
3. Internal Breaker Fault
(non-Bus-tie Breaker)

4. Internal Breaker Fault (Bus-tie Breaker)

Adopted by NERC Board of Trustees: August 4, 2011

EHV

Yes

EHV, HV

Yes

SLG
8

SLG

Standard TPL-001-24 — Transmission System Planning Performance Requirements
Category

P3
Multiple
Contingency

Initial Condition

Loss of generator unit
followed by System
adjustments9

Event

Loss of one of the following:
1. Generator
2. Transmission Circuit
5
3. Transformer
4. Shunt Device 6
5. Single pole of a DC line

P4
Multiple
Contingency
(Fault plus stuck
breaker10)

Normal System

P5
Multiple
Contingency
(Fault plus relay
failure to
operate)

Normal System

P6
Multiple
Contingency
(Two
overlapping
singles)

Loss of one of the
following followed by
9
System adjustments.
1. Transmission Circuit
5
2. Transformer
6
3. Shunt Device
4. Single pole of a DC line

Adopted by NERC Board of Trustees: August 4, 2011

Fault Type 2

BES Level 3

Interruption of Firm
Transmission
Service Allowed 4

Non-Consequential
Load Loss Allowed

3Ø

EHV, HV

No9

No12

EHV

Yes

EHV, HV

Yes

EHV

Yes

EHV, HV

Yes

EHV, HV

Yes

SLG
9

SLG

3Ø

SLG

Standard TPL-001-24 — Transmission System Planning Performance Requirements
Category
P7
Multiple
Contingency
(Common
Structure)

Initial Condition

Normal System

Event

The loss of:
1. Any two adjacent (vertically or
horizontally) circuits on common
11
structure
2. Loss of a bipolar DC line

Adopted by NERC Board of Trustees: August 4, 2011

Fault Type 2

BES Level 3

Interruption of Firm
Transmission
Service Allowed 4

Non-Consequential
Load Loss Allowed

SLG

EHV, HV

Yes

Standard TPL-001-24 — Transmission System Planning Performance Requirements

Adopted by NERC Board of Trustees: August 4, 2011

Standard TPL-001-24 — Transmission System Planning Performance Requirements

Table 1 – Steady State & Stability Performance Footnotes
(Planning Events and Extreme 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 stated performance criteria regarding allowances for interruptions of Firm Transmission Service and Non-Consequential Load Loss.
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. Bulk Electric System (BES) level references include extra-high voltage (EHV) Facilities defined as greater than 300kV and high voltage (HV) Facilities defined
as the 300kV and lower voltage Systems. The designation of EHV and HV is used to distinguish between stated performance criteria allowances for
interruption of Firm Transmission Service and Non-Consequential Load Loss.
4. Curtailment of Conditional Firm Transmission Service is allowed when the conditions and/or events being studied formed the basis for the Conditional Firm
Transmission Service.
5. 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.
6. Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
7. 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.
8. 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.
9. An objective of the planning process should be to minimize the likelihood and magnitude of interruption of Firm Transmission Service following Contingency
events. Curtailment of Firm Transmission Service is allowed both as a System adjustment (as identified in the column entitled ‘Initial Condition’) and a
corrective action when achieved through the appropriate re-dispatch of resources obligated to re-dispatch, where it can be demonstrated that Facilities,
internal and external to the Transmission Planner’s planning region, remain within applicable Facility Ratings and the re-dispatch does not result in any NonConsequential Load Loss. Where limited options for re-dispatch exist, sensitivities associated with the availability of those resources should be considered.
10. 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.
11. Excludes circuits that share a common structure (Planning event P7, Extreme event steady state 2a) or common Right-of-Way (Extreme event, steady state
2b) for 1 mile or less.
12. An objective of the planning process should beis to minimize the likelihood and magnitude of Non-Consequential Load Loss following Contingencyplanning
events. However, inIn limited circumstances, Non-Consequential Load Loss may be needed to addressthroughout the planning horizon to ensure that BES
performance requirements. When are met. However, when Non-Consequential Load Loss is utilized under footnote 12 within the planning processNearTerm Transmission Planning Horizon to address BES performance requirements, such interruption is limited to circumstances where the Non-Consequential
Load Loss is documented, including alternatives evaluated; and where the utilization of Non-Consequential Load Loss is subject to review in an open and
transparent stakeholder process that includes addressing stakeholder commentsmeets the conditions shown in Attachment 1. In no case can the planned
Non-Consequential Load Loss under footnote 12 exceed 75 MW for US registered entities. The amount of planned Non-Consequential Load Loss for a nonUS Registered Entity should be implemented in a manner that is consistent with, or under the direction of, the applicable governmental authority or its agency
Adopted by NERC Board of Trustees: August 4, 2011

Standard TPL-001-24 — Transmission System Planning Performance Requirements
Table 1 – Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)
in the non-US jurisdiction.
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).